UNITED STATES SECURITIES AND EXCHANGE COMMISSION

FORM 10-Q

(Mark One)

For the quarterly period ended September 30, 2004

OR

For the transition period from                     to                    

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

Yes [X] No [  ]

     Indicate by check mark whether each registrant is an accelerated filer (as defined in Rule 12b-2 of the Act):

     Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:

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

     This combined Form 10-Q is separately filed by FirstEnergy Corp., Ohio Edison Company, Pennsylvania Power Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. No registrant makes any representation as to information relating to any other registrant, except that information relating to any of the FirstEnergy subsidiary registrants is also attributed to FirstEnergy Corp.

     This Form 10-Q includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties. These statements typically contain, but are not limited to, the terms “anticipate”, “potential”, “expect”, “believe”, “estimate” and similar words. Actual results may differ materially due to the speed and nature of increased competition and deregulation in the electric utility industry, economic or weather conditions affecting future sales and margins, changes in markets for energy services, changing energy and commodity market prices, replacement power costs being higher than anticipated or inadequately hedged, maintenance costs being higher than anticipated, legislative and regulatory changes (including revised environmental requirements), adverse regulatory or legal decisions and the outcome of governmental investigations (including revocation of necessary licenses or operating permits), availability and cost of capital, the continuing availability and operation of generating units, the inability to accomplish or realize anticipated benefits of strategic goals, the ability to improve electric commodity margins and to experience growth in the distribution business, the ability to access the public securities markets, further investigation into the causes of the August 14, 2003 regional power outages and the outcome, cost and other effects of present and potential legal and administrative proceedings and claims related to those outages, the final outcome in the proceeding related to FirstEnergy’s Application for a Rate Stabilization Plan in Ohio, the risks and other factors discussed from time to time in the registrants’ Securities and Exchange Commission filings, including their annual report on Form 10-K (as amended) for the year ended December 31, 2003 and other similar factors. The registrants expressly disclaim any current intention to update any forward-looking statements contained in this document as a result of new information, future events, or otherwise.

TABLE OF CONTENTS

TABLE OF CONTENTS (Cont’d)

GLOSSARY OF TERMS

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

     The following abbreviations and acronyms are used to identify frequently used terms in this report:

i

GLOSSARY OF TERMS, Cont.

ii 

GLOSSARY OF TERMS, Cont.

iii 

PART I. FINANCIAL INFORMATION

FIRSTENERGY CORP. AND SUBSIDIARIES
OHIO EDISON COMPANY AND SUBSIDIARIES
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES
THE TOLEDO EDISON COMPANY AND SUBSIDIARY
PENNSYLVANIA POWER COMPANY AND SUBSIDIARY
JERSEY CENTRAL POWER & LIGHT COMPANY AND SUBSIDIARIES
METROPOLITAN EDISON COMPANY AND SUBSIDIARIES
PENNSYLVANIA ELECTRIC COMPANY AND SUBSIDIARIES

1 - ORGANIZATION AND BASIS OF PRESENTATION:

          The principal business of FirstEnergy is the holding, directly or indirectly, of all of the outstanding common stock of its eight principal electric utility operating subsidiaries: OE, CEI, TE, Penn, ATSI, JCP&L, Met-Ed and Penelec. Penn is a wholly owned subsidiary of OE. JCP&L, Met-Ed and Penelec were acquired in a merger (which was effective November 7, 2001) with GPU, the former parent company of JCP&L, Met-Ed and Penelec. The merger was accounted for by the purchase method of accounting and the applicable effects were reflected on the financial statements of JCP&L, Met-Ed and Penelec as of the merger date. FirstEnergy’s consolidated financial statements also include its other principal subsidiaries: FENOC, FES and its subsidiary FGCO, FESC, FirstCom, FSG, GPU Capital, GPU Power and MYR.

          FirstEnergy and its subsidiaries follow GAAP and comply with the regulations, orders, policies and practices prescribed by the SEC, FERC and, as applicable, PUCO, PPUC and NJBPU. The consolidated unaudited financial statements of FirstEnergy and each of the Companies reflect all normal recurring adjustments that, in the opinion of management, are necessary to fairly present results of operations for the interim periods. Certain prior year amounts have been reclassified to conform with the current year presentation. In particular, expenses (including transmission and congestion charges) were reclassified among purchased power, other operating costs and depreciation and amortization to conform with the current year presentation of generation commodity costs. As discussed in Note 8, segment reporting in 2003 was reclassified to conform with the current year business segment organizations and operations. In addition, revenues, expenses and taxes related to certain divestitures in 2003 have been reclassified and reported net as discontinued operations (see Note 2) and certain revenues and expenses have been reclassified and presented on a net basis to conform with the current year presentation.

          These statements should be read in conjunction with the financial statements and notes included in the combined Annual Report on Form 10-K for the year ended December 31, 2003 for FirstEnergy and the Companies. The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities. Actual results could differ from those estimates. The reported results of operations are not indicative of results of operations for any future period.

          FirstEnergy’s and the Companies’ independent registered public accounting firm has performed reviews of, and issued reports on, these consolidated interim financial statements in accordance with standards established by the PCAOB. Pursuant to Rule 436(c) under the Securities Act of 1933, their reports of those reviews should not be considered a report within the meaning of Section 7 and 11 of that Act, and the independent registered public accounting firm’s liability under Section 11 does not extend to them.

2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

     Consolidation

          FirstEnergy and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest, and VIEs for which FirstEnergy or any of its subsidiaries is the primary beneficiary. Intercompany transactions and balances are eliminated in consolidation. Investments in nonconsolidated affiliates (20-50 percent owned companies, joint ventures and partnerships) over which FirstEnergy and its subsidiaries have the ability to exercise significant influence, but not control, are accounted for on the equity basis.

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          FIN 46R addresses the consolidation of VIEs, including SPEs, that are not controlled through voting interests or in which the equity investors do not bear the residual economic risks and rewards. The first step under FIN 46R is to determine whether an entity is within the scope of FIN 46R, which occurs if it is deemed to be a VIE. FirstEnergy and its subsidiaries consolidate VIEs where they have determined that they are the primary beneficiaries as defined by FIN 46R.

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

          PNBV was established to purchase a portion of the lease obligation bonds issued in connection with OE’s 1987 sale and leaseback of its interests in the Perry Plant and Beaver Valley Unit 2. OE used debt and available funds to purchase the notes issued by PNBV. Ownership of PNBV includes a three-percent equity interest by a nonaffiliated third party and a three-percent equity interest held by OES Ventures, a wholly owned subsidiary of OE. As required by FIN 46R, consolidation of PNBV by FirstEnergy and OE as of December 31, 2003 changed the previously reported trust investment of $361 million to an investment in collateralized lease bonds of $372 million. The $11 million increase represented the minority interest in the total assets of PNBV.

          Shippingport was established to purchase all of the lease obligation bonds issued in connection with CEI’s and TE’s Bruce Mansfield Plant sale and leaseback transaction in 1987. CEI and TE used debt and available funds to purchase the notes issued by Shippingport. Consolidation of this entity by CEI impacted the financial statements of CEI and TE but had no impact on the consolidated financial statements of FirstEnergy. Prior to the adoption of FIN 46R, the assets and liabilities of Shippingport were included on a proportionate basis in the financial statements of CEI and TE. Adoption of FIN 46R resulted in the consolidation of Shippingport by CEI as of December 31, 2003. Shippingport’s note payable to TE of $199 million ($10 million current) and $208 million ($9 million current) as of September 30, 2004 and December 31, 2003, respectively, is included in long-term debt on CEI’s Consolidated Balance Sheets.

          Through its investment in PNBV, OE has, and through their investments in Shippingport, CEI and TE have, variable interests in certain owner trusts that acquired the interests in the Perry Plant and Beaver Valley Unit 2, in the case of OE, and the Bruce Mansfield Plant, in the case of CEI and TE. FirstEnergy concluded that OE, CEI and TE were not the primary beneficiaries of the relevant owner trusts and were therefore not required to consolidate these entities. The leases are accounted for as operating leases in accordance with GAAP. The combined purchase price of $3.1 billion for all of the interests acquired by the owner trusts in 1987 was funded with debt of $2.5 billion and equity of $600 million.

          Each of OE, CEI and TE are exposed to losses under the applicable sale-leaseback agreements upon the occurrence of certain contingent events that each company considers unlikely to occur. OE, CEI and TE each have a maximum exposure to loss under these provisions of approximately $1 billion, which represents the net amount of casualty value payments upon the occurrence of specified casualty events that render the applicable plant worthless. Under the applicable sale and leaseback agreements, OE, CEI and TE have net minimum discounted lease payments of $696 million, $113 million and $572 million, respectively, that would not be payable if the casualty value payments are made. As of September 30, 2004, CEI and TE have recorded above-market lease obligations related to the Bruce Mansfield Plant and Beaver Valley Unit 2 totaling $1.0 billion (CEI–$744 million and TE–$299 million), of which $85 million (CEI–$60 million and TE–$25 million) is current.

          CEI formed a wholly owned statutory business trust to sell preferred securities and invest the gross proceeds in 9% subordinated debentures of CEI. The sole assets of the trust are the subordinated debentures with an aggregate principal amount of $103 million. The trust’s preferred securities are redeemable at 100% of their principal amount at CEI’s option beginning in December 2006. CEI has effectively provided a full and unconditional guarantee of the trust’s obligations under the preferred securities.

          Met-Ed and Penelec each formed statutory business trusts for substantially similar transactions to those of CEI. However, ownership of the Met-Ed and Penelec trusts is through separate wholly owned limited partnerships. On June 1, 2004, Met-Ed extinguished the subordinated debentures held by its affiliated trust and redeemed all of the associated 7.35% preferred securities (aggregate value of $100 million). On September 1, 2004, Penelec extinguished the subordinated debentures held by its affiliated trust and redeemed all of the associated 7.34% preferred securities (aggregate value of $100 million).

          Upon adoption of FIN 46R, the limited partnerships and statutory business trusts discussed above were no longer consolidated on the financial statements of FirstEnergy or, as applicable, CEI, Met-Ed or Penelec. As of December 31, 2003 and September 30, 2004, subordinated debentures held by the affiliated trusts were included in long-term debt of the applicable company and equity investments in the trusts were included in other investments.

          FirstEnergy 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 Companies and the contract price for power is correlated with the plant’s variable costs of production. FirstEnergy, through its subsidiaries JCP&L, Met-Ed and

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Penelec, maintains approximately 30 long-term power purchase agreements with NUG entities. The agreements were structured pursuant to the Public Utility Regulatory Policies Act of 1978. FirstEnergy was not involved in the creation of, and has no equity or debt invested in, these entities.

FirstEnergy has determined that for all but nine of these entities, neither JCP&L, Met-Ed or Penelec have variable interests in the entities or the entities are governmental or not-for-profit organizations not within the scope of FIN 46R. JCP&L, Met-Ed or Penelec may hold variable interests in the remaining nine entities, which sell their output at variable prices that correlate to some extent with the operating costs of the plants.

As required by FIN 46R, FirstEnergy has requested each quarter the information necessary from these nine entities to determine whether they are VIEs or whether JCP&L, Met-Ed or Penelec is the primary beneficiary. FirstEnergy has been unable to obtain the requested information, which in most cases, was deemed by the requested entity to be competitive and proprietary. As such, FirstEnergy applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities under FIN 46R. The maximum exposure to loss from these entities results from increases in the variable pricing component under the contract terms and cannot be determined without the requested data. The purchased power costs from these entities during the three months and nine months ended September 30, 2004 and 2003 were as follows:

          FirstEnergy is required to continue to make exhaustive efforts to obtain the necessary information in future periods and is unable to determine the possible impact of consolidating any such entity without this information.

     Earnings Per Share

          Basic earnings per share are computed using the weighted average of actual common shares outstanding during the respective period as the denominator. The denominator for diluted earnings per share reflects the weighted average of common shares outstanding plus the potential additional common shares that could result if dilutive securities and other agreements to issue common stock were exercised. Stock-based awards to purchase shares of common stock totaling 3.4 million in the nine months ended September 30, 2004 and 3.5 million in the three months and nine months ended September 30, 2003 were excluded from the calculation of diluted earnings per share of common stock because their exercise prices were greater than the average market price of common shares during the period. No stock-based awards were excluded from the calculation for the quarter ended September 30, 2004. The following table reconciles the denominators for basic and diluted earnings per share from Income Before Discontinued Operations and Cumulative Effect of Accounting Change:

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     Preferred Stock Subject to Mandatory Redemption

          Long-term debt includes the preferred stock of consolidated subsidiaries subject to mandatory redemption as of September 30, 2004 and December 31, 2003 in accordance with SFAS 150. Issued in May 2003 and effective July 1, 2003, SFAS 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity; certain financial instruments that embody obligations for the issuer are required to be classified as liabilities. The adoption of SFAS 150 had no impact on FirstEnergy’s Consolidated Statements of Income because dividends on applicable subsidiary preferred stock were previously included in net interest charges and required no reclassification. CEI and Penn, however, did not include the preferred dividends on their manditorily redeemable preferred stock in interest expense for the first six months of 2003, but have included the dividends in interest charges for the three months ended September 30, 2004 and 2003, and the nine months ended September 30, 2004.

     Securitized Transition Bonds

          The consolidated financial statements of FirstEnergy and JCP&L include the results of JCP&L Transition, a wholly owned limited liability company of JCP&L. In June 2002, JCP&L Transition sold $320 million of transition bonds to securitize the recovery of JCP&L’s bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station.

          JCP&L did not purchase and does not own any of the transition bonds, which are included as long-term debt on FirstEnergy’s and JCP&L’s Consolidated Balance Sheets. The transition bonds are obligations of JCP&L Transition only and are collateralized solely by the equity and assets of JCP&L Transition, which consist primarily of bondable transition property. The bondable transition property is solely the property of JCP&L Transition.

          Bondable transition property represents the irrevocable right under New Jersey law of a utility company to charge, collect and receive from its customers, through a non-bypassable TBC, the principal amount and interest on the transition bonds and other fees and expenses associated with their issuance. JCP&L sold the bondable transition property to JCP&L Transition and, as servicer, manages and administers the bondable transition property, including the billing, collection and remittance of the TBC, pursuant to a servicing agreement with JCP&L Transition. JCP&L is entitled to a quarterly servicing fee of $100,000 that is payable from TBC collections.

     Derivative Accounting

          FirstEnergy is exposed to financial risks resulting from the fluctuation of interest rates and commodity prices, including electricity, natural gas and coal. To manage the volatility relating to these exposures, FirstEnergy uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes, and to a lesser extent, for trading purposes. FirstEnergy’s Risk Policy Committee, comprised of executive officers, exercises an independent risk oversight function to ensure compliance with corporate risk management policies and prudent risk management practices.

          Derivatives are recognized as assets or liabilities at fair value unless they qualify for an exception under SFAS 133. All changes in the fair value of derivatives are recognized currently in earnings unless specific hedge criteria are met. Gains and losses from derivative contracts that do not qualify as hedges of commodity price or interest rate risk are included in other operating expenses.

          SFAS 133 provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of other comprehensive income and be reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. The ineffective portion of hedge gains and losses is also included in net income. FirstEnergy’s primary ongoing hedging activity involves cash flow hedges of electricity and natural gas purchases. The maximum periods over which the variability of electricity and natural gas cash flows are hedged are two and three years, respectively. In 2001, FirstEnergy entered into interest rate derivative transactions to hedge a portion of the anticipated interest payments on debt related to the GPU acquisition. Gains and losses from these cash flow hedges were reported in other comprehensive income and are included in net income over the periods that the hedged interest payments are made – 5, 10 and 30 years.

          The net deferred loss of $93 million included in AOCL as of September 30, 2004, for derivative hedging activity, as compared to the June 30, 2004 balance of $100 million in net deferred losses, resulted from a $5 million reduction related to current hedging activity and a $2 million decrease due to net hedge losses included in earnings during the three months ended September 30, 2004. Approximately $12 million (after tax) of the net deferred loss on derivative instruments in AOCL as of September 30, 2004, is expected to be reclassified to earnings during the next twelve months as hedged transactions occur. The fair value of these derivative instruments will fluctuate from period to period based on various market factors.

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          FirstEnergy has entered into fair value hedges of fixed-rate, long-term debt issues to protect against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, call options, fixed interest rates received, and interest payment dates match those of the underlying debt obligations. As of September 30, 2004, FirstEnergy maintained fixed-for-floating interest rate swap agreements with an aggregate notional amount of $1.7 billion. Under these agreements, FirstEnergy receives fixed cash flows based on the fixed coupons of hedged securities and pays variable cash flows based on short-term variable market interest rates. The weighted average fixed interest rate of senior notes and subordinated debentures hedged by the swap agreements was 5.53%. The interest rate swaps have effectively converted that rate to a current, weighted average variable interest rate of 3.02%. Changes in the fair value of derivatives designated as fair value hedges and the corresponding changes in the fair value of the hedged risk attributable to a recognized asset, liability, or unrecognized firm commitment are recorded in earnings. If the fair value hedge is effective, the amounts recorded will offset in earnings. FirstEnergy did not enter into any new fixed-for-floating interest rate swap agreements during the third quarter of 2004.

     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, FirstEnergy 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, FirstEnergy 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. FirstEnergy’s 2003 annual review resulted in a non-cash goodwill impairment charge of $122 million in the third quarter of 2003, reducing the carrying value of FSG. Of this amount, $117 million was reported as an operating expense and $5 million was included in the results from discontinued operations. The impairment charge reflected the slow down in the development of competitive retail markets and depressed economic conditions that affected the value of FSG. The fair value of FSG was estimated using primarily the expected discounted future cash flows. FirstEnergy’s 2004 annual review was completed in the third quarter of 2004 with no impairment indicated.

          As of September 30, 2004, FirstEnergy had $6.1 billion of goodwill that primarily relates to its regulated services segment. In the first nine months of 2004, FirstEnergy adjusted goodwill related to the former GPU companies for interest received on a pre-merger income tax refund and for the reversal of tax valuation allowances related to income tax benefits realized attributable to prior period capital loss carryforwards that were offset by capital gains generated in 2004. A summary of the change in goodwill during the nine months ended September 30, 2004 is shown below:

     Asset Retirement Obligations

          FirstEnergy recognizes a liability for retirement obligations associated with tangible assets in accordance with SFAS 143. FirstEnergy has identified applicable legal obligations as defined under the standard for nuclear power plant decommissioning, reclamation of a sludge disposal pond related to the Bruce Mansfield Plant and closure of two coal ash disposal sites. The ARO liability was $1.060 billion as of September 30, 2004 and included $1.046 billion for nuclear decommissioning of the Beaver Valley, Davis-Besse, Perry and TMI-2 nuclear generating facilities. The Companies’ share of the obligation to decommission these units was developed based on site specific studies performed by an independent engineer. FirstEnergy utilized an expected cash flow approach (as discussed in FCON 7) to measure the fair value of the nuclear decommissioning ARO.

          In the third quarter of 2004, FirstEnergy revised the ARO associated with TMI-2 as the result of a recently completed study and the anticipated operating license extension at TMI-1. The abandoned TMI-2 is adjacent to TMI-1 and the units will be decommissioned on a concurrent timeline. The license holder at TMI-1 has indicated plans to file for a 20-year extension of its operating license, which currently expires in 2014. The decrease in the present value of estimated cash flows associated with the license extension of $202 million, was partially offset by the $26 million present value of an increase in projected decommissioning costs. The net decrease in the TMI-2 ARO liability and corresponding regulatory asset was $176 million (JCP&L — $43 million, Met-Ed - $89 million and Penelec — $44 million).

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          The Companies maintain nuclear decommissioning trust funds that are legally restricted for purposes of settling the nuclear decommissioning ARO. As of September 30, 2004, the fair value of the decommissioning trust assets was $1.462 billion.

          The following tables provide the beginning and ending aggregate carrying amount of the ARO and the changes to the balance during the three months and nine months ended September 30, 2004 and 2003, respectively.

     Stock-Based Compensation

          FirstEnergy applies the recognition and measurement principles of APB 25 and related Interpretations in accounting for its stock-based compensation plans. No material stock-based employee compensation expense is reflected in net income as all options granted under those plans have exercise prices equal to the market value of the underlying common stock on the respective grant dates, resulting in substantially no intrinsic value.

          In March 2004, the FASB issued an exposure draft of a proposed standard that, if adopted, will change the accounting for employee stock options and other equity-based compensation. The proposed standard would require companies to expense the fair value of stock options determined on the grant date. In October 2004, the FASB amended the proposed standard to delay its effective date from January 1, 2005 to interim and annual periods beginning after June 15, 2005 (see Note 7). FirstEnergy will not be able to determine the impact of the proposed standard until it is issued in final form. The table below summarizes the effects on the Company’s net income and earnings per share had the Company applied the fair value recognition provisions of SFAS 123 to stock-based employee compensation in the current reporting periods.

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     Discontinued Operations

          FirstEnergy’s discontinued operations consisted of net income of $1 million in the third quarter of 2003 and net losses of $65 million in the first nine months of 2003 from its Argentina and Bolivia businesses and certain domestic operations divested in 2003. The related revenues, expenses and taxes were reclassified from the previously reported Consolidated Statement of Income for the nine months ended September 30, 2003 and reported as a net amount in Discontinued Operations. In April 2003, FirstEnergy divested its ownership in Emdersa through the abandonment of its shares in Emdersa’s parent company, GPU Argentina Holdings, Inc. The abandonment was accomplished by relinquishing FirstEnergy’s shares to the independent Board of Directors of GPU Argentina Holdings, relieving FirstEnergy of all rights and obligations relative to this business. As a result of the abandonment, FirstEnergy recognized a one-time, non-cash charge of $67 million (no income tax benefit was recognized), or $0.23 per share of common stock, in the second quarter of 2003. This charge resulted from realizing CTA losses through earnings ($90 million, or $0.30 per share of common stock), partially offset by the gain recognized from abandoning FirstEnergy’s investment in Emdersa ($23 million, or $0.07 per share of common stock). Since FirstEnergy had previously recorded $90 million of CTA adjustments in OCI, the net effect of the $67 million charge was an increase in common stockholders’ equity of $23 million. FirstEnergy sold its Bolivia operations, Empresa Guaracachi S.A., in December 2003. Domestic operations sold in 2003 consisted of three former FSG subsidiaries and the MARBEL subsidiary, NEO.

     Cumulative Effect of Accounting Change

          As a result of adopting SFAS 143 in January 2003, FirstEnergy recorded a $175 million increase to income, $102 million net of tax, or basic earnings of $0.35 per share ($0.34 diluted) of common stock in the nine months ended September 30, 2003. Upon adoption of the accounting standard, FirstEnergy reversed accrued nuclear plant decommissioning costs of $1.23 billion and recorded an ARO of $1.11 billion, including accumulated accretion of $507 million for the period from the date the liability was incurred to the date of adoption. FirstEnergy also recorded asset retirement costs of $602 million as part of the carrying amount of the related long-lived asset and accumulated depreciation of $415 million. FirstEnergy recognized a regulatory liability of $185 million for the transition amounts expected to be recovered through rates related to the ARO for nuclear decommissioning. The cumulative effect adjustment also included the reversal of $60 million in accumulated estimated removal costs for non-regulated generation assets.

          The impact of adopting SFAS 143 on the financial statements of each of the Companies effective January 1, 2003, is shown in the table below:

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     Restatements of TE, JCP&L and Penelec Previously Reported Quarterly Results

          Earnings for the three months and nine months ended September 30, 2003 have been restated for TE, JCP&L and Penelec to reflect adjustments to costs that were subsequently capitalized to construction projects. The results for TE have also been restated to correct the amount reported for interest expense. TE’s costs, which were originally recorded as operating expenses and subsequently capitalized to construction, were $1.1 million ($0.7 million after-tax) and $2.1 million ($1.2 million after-tax) in the third quarter and the first nine months of 2003, respectively. TE’s interest expense was overstated by $0.3 million ($0.2 million after-tax) and $1.6 million ($1.0 million after-tax) in the third quarter and the first nine months of 2003, respectively. Similar to TE, JCP&L’s capital costs originally recorded as operating expenses were $5.8 million ($3.4 million after-tax) and $9.0 million ($5.3 million after-tax) in the third quarter and the first nine months of 2003, respectively. Penelec’s capital costs originally recorded as operating expenses were $2.0 million ($1.2 million after-tax) and $2.7 million ($1.6 million after-tax) in the third quarter and the first nine months of 2003, respectively. In addition, certain revenues and expenses have been reclassified and presented on a net basis to conform with the current year presentation (see Note 1). The impacts of these adjustments were not material to the consolidated balance sheets or consolidated statements of cash flows for TE, JCP&L or Penelec for any quarter of 2003.

          The effects of these adjustments on the consolidated statements of income previously reported for TE, JCP&L and Penelec for the three months and nine months ended September 30, 2003 are as follows:

TE

JCP&L

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Penelec

3 — COMMITMENTS, GUARANTEES AND CONTINGENCIES:

     Capital Expenditures

          FirstEnergy’s current forecast reflects expenditures of approximately $2.3 billion (OE–$295 million, CEI–$275 million, TE–$141 million, Penn–$143 million, JCP&L–$446 million, Met-Ed–$168 million, Penelec–$198 million, ATSI–$66 million, FES–$443 million and other subsidiaries–$125 million) for property additions and improvements from 2004-2006, of which approximately $717 million (OE–$113 million, CEI–$92 million, TE–$48 million, Penn–$65 million, JCP&L–$142 million, Met-Ed–$53 million, Penelec–$60 million, ATSI–$24 million, FES–$87 million and other subsidiaries-$33 million) is applicable to 2004. Investments for additional nuclear fuel during the 2004-2006 period are estimated to be approximately $303 million (OE–$84 million, CEI–$100 million, TE–$64 million and Penn–$55 million), of which approximately $90 million (OE–$26 million, CEI–$30 million, TE–$16 million and Penn–$18 million) applies to 2004.

     Guarantees and Other Assurances

          As part of normal business activities, FirstEnergy and the Companies enter into various agreements to provide financial or performance assurances to third parties. As of September 30, 2004, outstanding guarantees and other assurances aggregated $2.1 billion and included contract guarantees ($1.0 billion), surety bonds ($0.3 billion) and letters of credit ($0.8 billion).

          FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy marketing activities – principally to facilitate normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of subsidiary financing principally for the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy and its subsidiaries to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financing where the law might otherwise limit the counterparties’ claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy’s guarantee enables the counterparty’s legal claim to be satisfied by other FirstEnergy assets. The likelihood is remote that such parental guarantees of $0.9 billion (included in the $1.0 billion discussed above) as of September 30, 2004 will increase amounts otherwise to be paid by FirstEnergy to meet its obligations incurred in connection with financings and ongoing energy and energy-related activities.

          While guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade or “material adverse event” the immediate payment of cash collateral or provision of an LOC may be required. The following table summarizes collateral provisions as of September 30, 2004:

(1)

As of October 12, 2004, FirstEnergy’s total exposure decreased to $465 million and the remaining exposure decreased to $272 million – net of $152 million of cash collateral and $41 million of LOC provided to counterparties.

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          Most of FirstEnergy’s surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related FirstEnergy guarantees of $280 million provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction jobs, environmental commitments and various retail transactions.

          In connection with the sale of the TEBSA project in Colombia in January 2004, FirstEnergy guaranteed the obligations of the operators of the project, up to a maximum of $6 million (subject to escalation) under the project’s operation and maintenance agreement for so long as such obligations exist. The purchaser of TEBSA agreed to indemnify FirstEnergy against any loss under this guarantee. Also in connection with the TEBSA project, FirstEnergy has provided the TEBSA project lenders with a $60 million LOC and a $400,000 LOC. The $60 million LOC was established as a substitute asset for FirstEnergy’s interest in its Midlands companies pursuant to an indemnity agreement in favor of the TEBSA project lenders. As of October 15, 2004, the value of the LOC decreased to $46 million. The balance will continue to decline annually and will be fully discharged and released in October 2010. The substitute LOC enabled FirstEnergy to sell its remaining 20.1% interest in Avon (parent of Midlands Electricity in the United Kingdom). The $400,000 LOC was established to secure the TEBSA project lenders in the event that liquidated shares of TEBSA were unable to be converted into U.S. currency. The $400,000 LOC will terminate upon the registration of certain of TEBSA’s stock with the Colombian Central Bank.

     Environmental Matters

          Various federal, state and local authorities regulate the Companies with regard to air and water quality and other environmental matters. The effects of compliance on the Companies with regard to environmental matters could have a material adverse effect on FirstEnergy’s earnings and competitive position. These environmental regulations affect FirstEnergy’s earnings and competitive position to the extent that it competes with companies that are not subject to such regulations and therefore do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. Overall, FirstEnergy believes it is in material compliance with existing regulations but is unable to predict future change in regulatory policies and what, if any, the effects of such change would be. FirstEnergy estimates additional capital expenditures for environmental compliance of approximately $91 million for 2004 through 2006, which is included in the $2.3 billion of forecasted capital expenditures for 2004 through 2006.

     Clean Air Act Compliance

          The Companies are required to meet federally approved SO₂ regulations. Violations of such regulations can result in shutdown of the generating unit involved and/or civil or criminal penalties of up to $31,500 for each day the unit is in violation. The EPA has an interim enforcement policy for SO₂ regulations in Ohio that allows for compliance based on a 30-day averaging period. The Companies cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.

          The Companies believe they are complying with SO₂ reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NO_x reductions required by the 1990 Amendments are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NO_x reductions from the Companies’ facilities. The EPA’s NO_x Transport Rule imposes uniform reductions of NO_x emissions (an approximate 85% reduction in utility plant NO_x emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NO_x emissions are contributing significantly to ozone levels in the eastern United States. SIPs were required to comply by May 31, 2004 with individual state NO_x budgets. New Jersey and Pennsylvania submitted a SIP that required compliance with the state NO_x budgets at the Companies’ New Jersey and Pennsylvania facilities by May 1, 2003. Michigan and Ohio submitted a SIP that required compliance with the state NO_x budgets at the Companies’ Michigan and Ohio facilities by May 31, 2004. The Companies believe their facilities are complying with the state NO_x budgets through combustion controls and post-combustion controls, including Selective Catalytic Reduction and Selective Non-Catalytic Reduction systems, and/or using emission allowances.

     National Ambient Air Quality Standards

          In July 1997, the EPA promulgated changes in the NAAQS for ozone and proposed a new NAAQS for fine particulate matter. On December 17, 2003, the EPA proposed the “Interstate Air Quality Rule” covering a total of 29 states (including New Jersey, Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air pollution emissions from 29 eastern states and the District of Columbia significantly contribute to nonattainment of the NAAQS for fine particles and/or the “8-hour” ozone NAAQS in other states. The EPA has proposed the Interstate Air Quality Rule to “cap-and-trade” NO_x and SO₂ emissions in two phases (Phase I in 2010 and Phase II in 2015). According to the EPA, SO₂ emissions would be reduced by approximately 3.6 million tons in 2010, across states covered by the rule, with reductions ultimately reaching more than 5.5 million tons annually. NO_x emission reductions would measure about 1.5 million tons in 2010 and 1.8 million tons in 2015. The future cost of compliance with these proposed regulations

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may be substantial and will depend on whether and how they are ultimately implemented by the states in which the Companies operate affected facilities.

     Mercury Emissions

          In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. On December 15, 2003, the EPA proposed two different approaches to reduce mercury emissions from coal-fired power plants. The first approach would require plants to install controls known as MACT based on the type of coal burned. According to the EPA, if implemented, the MACT proposal would reduce nationwide mercury emissions from coal-fired power plants by 14 tons to approximately 34 tons per year. The second approach proposes a cap-and-trade program that would reduce mercury emissions in two distinct phases. Initially, mercury emissions would be reduced by 2010 as a “co-benefit” from implementation of SO₂ and NO_x emission caps under the EPA’s proposed Interstate Air Quality Rule. Phase II of the mercury cap-and-trade program would be implemented in 2018 to cap nationwide mercury emissions from coal-fired power plants at 15 tons per year. The EPA has agreed to choose between these two options and issue a final rule by March 15, 2005. The future cost of compliance with these regulations may be substantial.

     W. H. Sammis Plant

          In 1999 and 2000, the EPA issued NOV or Compliance Orders to nine utilities covering 44 power plants, including the W. H. Sammis Plant, which is owned by OE and Penn. In addition, the U.S. Department of Justice filed eight civil complaints against various investor-owned utilities, which included a complaint against OE and Penn in the U.S. District Court for the Southern District of Ohio. These cases are referred to as New Source Review cases. The NOV and complaint allege violations of the Clean Air Act based on operation and maintenance of the W. H. Sammis Plant dating back to 1984. The complaint requests permanent injunctive relief to require the installation of “best available control technology” and civil penalties of up to $27,500 per day of violation. On August 7, 2003, the United States District Court for the Southern District of Ohio ruled that 11 projects undertaken at the W. H. Sammis Plant between 1984 and 1998 required pre-construction permits under the Clean Air Act. The ruling concludes the liability phase of the case, which deals with applicability of Prevention of Significant Deterioration provisions of the Clean Air Act. The remedy phase trial to address civil penalties and what, if any, actions should be taken to further reduce emissions at the plant has been rescheduled to January 2005 by the Court because the parties are engaged in meaningful settlement negotiations. The Court indicated, in its August 2003 ruling, that the remedies it “may consider and impose involved a much broader, equitable analysis, requiring the Court to consider air quality, public health, economic impact, and employment consequences. The Court may also consider the less than consistent efforts of the EPA to apply and further enforce the Clean Air Act.” The potential penalties that may be imposed, as well as the capital expenditures necessary to comply with substantive remedial measures that may be required, could have a material adverse impact on FirstEnergy’s, OE’s and Penn’s respective financial condition and results of operations. While the parties are engaged in meaningful settlement discussions, management is unable to predict the ultimate outcome of this matter and no liability has been accrued as of September 30, 2004.

     Regulation of Hazardous Waste

          As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA’s evaluation of the need for future regulation. The EPA subsequently determined that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhazardous waste.

          The Companies have been named as PRPs at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site are liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of September 30, 2004, based on estimates of the total costs of cleanup, the Companies’ proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. In addition, JCP&L has accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey; those costs are being recovered by JCP&L through a non-bypassable SBC. Included in Current Liabilities and Other Noncurrent Liabilities are accrued liabilities aggregating approximately $65 million (JCP&L–$45.8 million, CEI–$2.4 million, TE–$0.2 million, Met-Ed–$28,000, Penelec–$26,000, and other–$16.3 million) as of September 30, 2004. The Companies accrue environmental liabilities only when they can conclude that it is probable that they have an obligation for such costs and can reasonably determine the amount of such costs. Unasserted claims are reflected in the Companies’ determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable.

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     Climate Change

          In December 1997, delegates to the United Nations’ climate summit in Japan adopted an agreement, the Kyoto Protocol (Protocol), to address global warming by reducing the amount of man-made greenhouse gases emitted by developed countries by 5.2% from 1990 levels between 2008 and 2012. The United States signed the Protocol in 1998 but it failed to receive the two-thirds vote of the U.S. Senate required for ratification. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic greenhouse gas intensity – the ratio of emissions to economic output – by 18% through 2012.

          The Companies cannot currently estimate the financial impact of climate change policies, although the potential restrictions on CO₂ emissions could require significant capital and other expenditures. However, the CO₂ emissions per kilowatt-hour of electricity generated by the Companies is lower than many regional competitors due to the Companies’ diversified generation sources which includes low or non-CO₂ emitting gas-fired and nuclear generators.

     Clean Water Act

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

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

     Power Outages and Related Litigation

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

          In August 2002, the trial court granted partial summary judgment to JCP&L and dismissed the plaintiffs’ claims for consumer fraud, common law fraud, negligent misrepresentation, and strict products liability. In November 2003, the trial court granted JCP&L’s motion to decertify the class and denied plaintiffs’ motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The Appellate Court issued a decision on July 8, 2004, affirming the decertification of the originally certified class but remanding for certification of a class limited to those customers directly impacted by the outages of transformers in Red Bank, New Jersey. On September 8, 2004, the New Jersey Supreme Court denied the motions filed by plaintiffs and JCP&L for leave to appeal the decision of the Appellate Court. FirstEnergy is unable to predict the outcome of these matters and no liability has been accrued as of September 30, 2004.

          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. On April 5, 2004, the U.S. –Canada Power System Outage Task Force released its final report on the outages. In the final report, the Task Force concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concludes, 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 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 contains 46

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“recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations relate to broad industry or policy matters while one, including subparts, relates to activities the Task Force recommends be undertaken by FirstEnergy, MISO, PJM, and ECAR. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which are consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy certified to NERC on June 30, 2004, completion of various reliability recommendations and further received independent verification of completion status from a NERC verification team on July 14, 2004 (see Regulatory Matters below). FirstEnergy’s implementation of these recommendations included completion of the Task Force recommendations that were directed toward FirstEnergy. As many of these initiatives already were in process and budgeted in 2004, FirstEnergy does not believe that any incremental expenses associated with additional initiatives undertaken during 2004 will have a material effect on its operations or financial results. FirstEnergy notes, however, that the applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures. FirstEnergy has not accrued a liability as of September 30, 2004 for any expenditures in excess of those actually incurred through that date.

          Three substantially similar actions were filed in various Ohio state courts by plaintiffs seeking to represent customers who allegedly suffered damages as a result of the August 14, 2003 power outages. All three cases were dismissed for lack of jurisdiction. One case was refiled at the PUCO and the other two have been appealed. In addition to the one case that was refiled at the PUCO, the Ohio Companies were named as respondents in a regulatory proceeding that was initiated at the PUCO in response to complaints alleging failure to provide reasonable and adequate service stemming primarily from the August 14, 2003 power outages.

          One complaint has been filed against FirstEnergy in the New York State Supreme Court. In this case, several plaintiffs in the New York City metropolitan area allege that they suffered damages as a result of the August 14, 2003 power outages. None of the plaintiffs are customers of any FirstEnergy affiliate. FirstEnergy filed a motion to dismiss with the Court on October 22, 2004. No damage estimate has been provided and thus potential liability has not been determined.

          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 instituted 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 and results of operations.

     Nuclear Plant Matters

          FENOC received a subpoena in late 2003 from a grand jury sitting in the United States District Court for the Northern District of Ohio, Eastern Division requesting the production of certain documents and records relating to the inspection and maintenance of the reactor vessel head at the Davis-Besse plant. FirstEnergy is unable to predict the outcome of this investigation. In addition, FENOC remains subject to possible civil enforcement action by the NRC in connection with the events leading to the Davis-Besse outage in 2002. Further, a petition was filed with the NRC on March 29, 2004 by a group objecting to the NRC’s restart order of the Davis-Besse Nuclear Power Station. The Petition seeks, among other things, suspension of the Davis-Besse operating license. A June 2, 2004 ASLB denial of the petition was appealed to the NRC. FENOC and the NRC staff filed opposition briefs on June 24, 2004. If it were ultimately determined that FirstEnergy or its subsidiaries has legal liability or is otherwise made subject to enforcement action based on the Davis-Besse outage, it could have a material adverse effect on FirstEnergy’s or its subsidiaries’ financial condition and results of operations.

          On August 12, 2004, the NRC publicly disclosed that it was notifying FirstEnergy that it will increase its regulatory oversight of the Perry Nuclear Power Plant as a result of problems with safety system equipment over the past two years. OE, CEI, TE and Penn own and/or lease the Perry Nuclear Power Plant. The NRC noted that the plant continues to operate safely. The increased oversight will include an extensive NRC team inspection to access the equipment problems and FirstEnergy’s corrective actions. The outcome of this increased oversight is not known at this time.

     Other Legal Matters

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

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

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during the SEC’s examination of FirstEnergy and the Companies under the PUHCA. Concurrent with this notification, FirstEnergy received a subpoena asking for background documents and documents related to the restatements and Davis-Besse issues. FirstEnergy has cooperated fully with the informal inquiry and will continue to do so with the formal investigation.

          Various legal proceedings alleging violations of federal securities laws and related state laws were filed against FirstEnergy in connection with, among other things, the restatements in August 2003 by FirstEnergy and the Ohio Companies of previously reported results, the August 14, 2003 power outages described above, and the extended outage at the Davis-Besse Nuclear Power Station. The lawsuits were filed against FirstEnergy and certain of its officers and directors. On July 27, 2004, FirstEnergy announced that it had reached an agreement to resolve these pending lawsuits. The settlement agreement, which does not constitute any admission of wrongdoing, provides for a total settlement payment of $89.9 million. Of that amount, FirstEnergy’s insurance carriers will pay $71.92 million, based on a contractual pre-allocation, and FirstEnergy will pay $17.98 million, which resulted in an after-tax charge against FirstEnergy’s second quarter and year-to-date 2004 earnings of $11 million or $0.03 per share of common stock (basic and diluted). The settlement has been preliminarily approved by the court with a final hearing scheduled for mid-December 2004. Although not anticipated to occur, in the event that a significant number of shareholders do not accept the terms of the settlement, FirstEnergy and individual defendants have the right, but not the obligation, to set aside the settlement and recommence the litigation.

          On September 16, 2004, the FERC issued an order that imposed additional obligations on CEI under certain pre-Open Access transmission contracts among CEI and the cities of Cleveland and Painesville. Under the FERC’s decision, CEI may be responsible for a portion of new energy market charges imposed by the MISO when its energy markets begin in the spring of 2005. CEI filed for rehearing of the order from the FERC on October 18, 2004. The impact of the FERC decision on CEI is dependent upon many factors, including the arrangements made by the cities for transmission service, the startup date for the MISO energy market, and the resolution of the rehearing request, and cannot be determined at this time.

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

4 — PENSION AND OTHER POSTRETIREMENT BENEFITS:

          The components of FirstEnergy’s net periodic pension cost, including amounts capitalized, consisted of the following:

          In September 2004, FirstEnergy made a $500 million voluntary contribution to its pension plan. Prior to this contribution, projections indicated that cash contributions of approximately $600 million would have been required during the 2006 to 2007 time period under minimum funding requirements established by the IRS. The election to pre-fund the plan is expected to eliminate that funding requirement. Since the contribution is deductible for tax purposes, the after-tax cash impact of the voluntary contribution is approximately $300 million. The payment was funded by FirstEnergy’s subsidiaries through existing short-term credit arrangements, including available intercompany money pools, as follows:

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          The components of FirstEnergy’s net periodic other postretirement benefit cost, including amounts capitalized, consisted of the following:

          FirstEnergy contributed $17 million to its other postretirement benefit plans in the nine months ended September 30, 2004. The Company has no funding requirements for the remainder of 2004.

          Pension and postretirement benefit obligations are allocated to the subsidiaries employing the plan participants. The Companies capitalize employee benefits related to construction projects. The net periodic pension costs, including amounts capitalized, recognized by each of the Companies in the three and nine months ended September 30, 2004 and 2003 were as follows:

          The net periodic postretirement benefit costs, including amounts capitalized, recognized by each of the Companies in the three and nine months ended September 30, 2004 and 2003 were as follows:

          Pursuant to FSP 106-1 issued January 12, 2004, FirstEnergy began accounting for the effects of the Medicare Act effective January 1, 2004 because of a plan amendment during the quarter, which required remeasurement of the plan’s obligations. The plan amendment, which increases cost-sharing by employees and retirees effective January 1, 2005, reduced postretirement benefit costs during the three months and nine months ended September 30, 2004, by $13 million and $35 million, respectively.

          Consistent with the guidance in FSP 106-2 issued May 19, 2004, FirstEnergy recognized a reduction of $318 million in the accumulated postretirement benefit obligation as a result of the federal subsidy provided under the Medicare Act related to benefits for past service. The subsidy reduced net periodic postretirement benefit costs during the three months and nine months ended September 30, 2004, as follows:

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          The impact of the subsidy was not material to the financial statements of each of the Companies for the three and nine months ended September 30, 2004.

5 - DIVESTITURES:

          FirstEnergy completed the sale of its international operations during the quarter ended March 31, 2004 with the sales of its remaining 20.1% interest in Avon on January 16, 2004, and its 28.67% interest in TEBSA on January 30, 2004. Impairment charges related to Avon and TEBSA were recorded in the fourth quarter of 2003 and no gain or loss was recognized upon the sales in 2004. Avon, TEBSA and other international assets sold in 2003 were originally acquired as part of FirstEnergy’s November 2001 merger with GPU.

          FirstEnergy completed the sale of its 50% interest in GLEP on June 23, 2004. Proceeds of $220 million included cash of $200 million and the right, valued at $20 million, to participate for up to a 40% interest in future wells in Ohio. This transaction produced an after-tax loss of $7 million, or $0.02 per share of common stock, including the benefits of prior tax capital losses that had been previously fully reserved, which offset the capital gain from the sale.

6 - REGULATORY MATTERS:

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

	•		allowing the Companies’ electric customers to select their generation suppliers;
	•		establishing PLR obligations to non-shopping customers in the Companies’ service areas;
	•		allowing recovery of potentially stranded investment (or transition costs) not otherwise recoverable in a competitive generation market;
	•		itemizing (unbundling) the price of electricity into its component elements – including generation, transmission, distribution and stranded costs recovery charges;
	•		deregulating the Companies’ electric generation businesses;
	•		continuing regulation of the Companies’ transmission and distribution systems; and
	•		requiring corporate separation of regulated and unregulated business activities.

          However, despite these similarities, the specific approach taken by each state and for each of the Companies varies.

     Reliability Initiatives

          On October 15, 2003, NERC issued a letter to all NERC control areas and reliability coordinators requesting a review of various reliability practices. The Company response confirmed that its review was completed and that various enhancements were underway to current practices. On February 10, 2004, NERC issued its Recommended Actions to Prevent and Mitigate the Impacts of Future Cascading Blackouts, a portion of which were directed at the FirstEnergy companies and broadly focused on initiatives that were recommended for completion by June 30, 2004. FirstEnergy’s detailed implementation plan was endorsed by the NERC Board of Trustees on May 7, 2004. The various initiatives recommended by NERC were certified as complete by June 30, 2004, with one minor exception related to reactive testing of certain generators expected to be completed later in 2004.

          On February 26 and 27, 2004, certain FirstEnergy companies, as part of a NERC review of control area operations throughout the United States, participated in a NERC Control Area Readiness Audit. The final audit report, completed on May 6, 2004, identified positive observations and included various recommendations for reliability improvement. FirstEnergy reported completion of those recommendations on June 30, 2004, with one exception related to MISO’s implementation of a voltage stability tool expected to be completed later this year.

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           On April 5, 2004, the U.S. - Canada Power System Outage Task Force issued a Final Report on the August 14, 2003 power outages. The Final Report contains 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations relate to broad industry or policy matters while one, including subparts, relates to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM and ECAR. FirstEnergy completed the Task Force recommendations that were directed toward FirstEnergy and reported completion of those activities on June 30, 2004.

          With respect to each of the foregoing initiatives, FirstEnergy requested and NERC provided, a technical assistance team of experts to provide ongoing guidance and assistance in implementing and confirming timely and successful completion. NERC further assembled an independent verification team to confirm implementation of the foregoing initiatives required to be completed as of June 30, 2004. The NERC Verification Team reported, on July 14, 2004, that FirstEnergy has completed the recommended policies, procedures and actions required to be completed by June 30, 2004 or summer 2004, with exceptions noted by FirstEnergy. Implementation of the recommendations has not required incremental material investment or upgrades to existing equipment.

          On March 1, 2004, certain FirstEnergy companies filed, in accordance with a November 25, 2003 order from the PUCO, their plan for addressing certain issues identified by the PUCO from the U.S. – Canada Power System Outage Task Force interim report. In particular, the filing addressed upgrades to FirstEnergy’s control room computer hardware and software and enhancements to the training of control room operators. The PUCO will review the plan before determining the next steps, if any, in the proceeding.

          On April 22, 2004, FirstEnergy filed with the FERC the results of the FERC-ordered independent study of part of Ohio’s power grid. The study examined, among other things, the reliability of the transmission grid in critical points in the Northern Ohio area and the need, if any, for reactive power reinforcements during summers 2004 and 2009. Certain requested additional clarifications were provided to the FERC in October 2004. FirstEnergy completed the implementation of recommendations relating to 2004 by June 30, 2004, and is continuing to review results related to 2009. The estimated capital expenditures required by 2009 are not expected to have a material adverse effect on FirstEnergy’s financial results. FirstEnergy notes, however, that the FERC or other applicable government agencies and reliability coordinators may take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional, material expenditures.

          In late 2003, the PPUC issued a Tentative Order implementing new reliability benchmarks and standards. In connection therewith, the PPUC commenced a rulemaking procedure to amend the Electric Service Reliability Regulations to implement these new benchmarks, and required additional reporting on reliability. The PPUC ordered all Pennsylvania utilities to begin filing quarterly reports on November 1, 2003. On May 11, 2004, the PPUC issued an order approving the revised reliability benchmark and standards, including revised benchmarks and standards for Met-Ed, Penelec and Penn. The Order permitted Pennsylvania utilities to file in a separate proceeding to revise the recomputed benchmarks and standards if they have evidence, such as the impact of automated outage management systems, on the accuracy of the PPUC computed reliability indices. Met-Ed, Penelec and Penn filed a Petition for Amendment of Benchmarks with the PPUC on May 26, 2004 seeking amendment of the benchmarks and standards due to their implementation of automated outage management systems following restructuring. No procedural schedule or hearing date has been set for this proceeding. FirstEnergy is unable to predict the outcome of this proceeding.

          On January 16, 2004, the PPUC initiated a formal investigation of whether Met-Ed’s, Penelec’s and Penn’s “service reliability performance deteriorated to a point below the level of service reliability that existed prior to restructuring” in Pennsylvania. Hearings were held in early August 2004. On September 30, 2004, Met-Ed, Penelec and Penn filed a settlement agreement with the PPUC that addresses the issues related to this investigation. As part of the settlement, Met-Ed, Penelec and Penn agreed to enhance service reliability, performance reporting and communications with customers and to collectively maintain their current spending levels of at least $255 million annually on combined capital and operation and maintenance expenditures for transmission and distribution for the years 2005 through 2007. In November 2004, the PPUC accepted the recommendation of the ALJ approving the settlement.

     Ohio

          In July 1999, Ohio’s electric utility restructuring legislation, which allowed Ohio electric customers to select their generation suppliers beginning January 1, 2001, was signed into law. Among other things, the legislation provided for a 5% reduction on the generation portion of residential customers’ bills and the opportunity to recover transition costs, including regulatory assets, from January 1, 2001 through December 31, 2005 (market development period). The period for the recovery of regulatory assets only can be extended up to December 31, 2010. The recovery period extension is related to the customer shopping incentives recovery discussed below. The PUCO was authorized to determine the level of transition cost recovery, as well as the recovery period for the regulatory assets portion of those costs, in considering each Ohio electric utility’s transition plan application.

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          In July 2000, the PUCO approved FirstEnergy’s transition plan for the Ohio Companies as modified by a settlement agreement with major parties to the transition plan. The application of SFAS 71 to OE’s generation business and the nonnuclear generation businesses of CEI and TE was discontinued with the issuance of the PUCO transition plan order, as described further below. Major provisions of the settlement agreement consisted of approval of recovery of generation-related transition costs as filed of $4.0 billion net of deferred income taxes (OE–$1.6 billion, CEI–$1.6 billion and TE–$0.8 billion) and transition costs related to regulatory assets as filed of $2.9 billion net of deferred income taxes (OE–$1.0 billion, CEI–$1.4 billion and TE–$0.5 billion), with recovery through no later than 2006 for OE, mid-2007 for TE and 2008 for CEI, except where a longer period of recovery is provided for in the settlement agreement. The generation-related transition costs include $1.4 billion, net of deferred income taxes, (OE–$1.0 billion, CEI–$0.2 billion and TE–$0.2 billion) of impaired generating assets recognized as regulatory assets as described further below, $2.4 billion, net of deferred income taxes, (OE–$1.2 billion, CEI–$0.4 billion and TE–$0.8 billion) of above market operating lease costs and $0.8 billion, net of deferred income taxes, (CEI–$0.5 billion and TE–$0.3 billion) of additional plant costs that were reflected on CEI’s and TE’s regulatory financial statements.

          Also as part of the settlement agreement, FirstEnergy gives preferred access over its subsidiaries to nonaffiliated marketers, brokers and aggregators to 1,120 MW of generation capacity through 2005 at established prices for sales to the Ohio Companies’ retail customers. Customer prices are frozen through the five-year market development period, which runs through the end of 2005, except for certain limited statutory exceptions, including the 5% reduction referred to above.

          FirstEnergy’s Ohio customers choosing alternative suppliers receive an additional incentive applied to the shopping credit (generation component) of 45% for residential customers, 30% for commercial customers and 15% for industrial customers. The amount of the incentive is deferred for future recovery from customers through an extension of the regulatory transition charge. Under the modified Rate Stabilization Plan described below, the deferred incentives and deferred interest costs related to the incentives will be amortized on a dollar-for-dollar basis as the associated revenues are recognized.

          On October 21, 2003, the Ohio Companies filed an application with the PUCO to establish generation service rates beginning January 1, 2006, in response to expressed concerns by the PUCO about price and supply uncertainty following the end of the market development period. The filing included two options:

	•		A competitive auction, which would establish a price for generation that customers would be charged during the period covered by the auction, or
	•		A Rate Stabilization Plan, which would extend current generation prices through 2008, ensuring adequate generation supply at stable prices, and continuing the Ohio Companies’ support of energy efficiency and economic development efforts.

          Under that proposal, the Ohio Companies requested:

	•		Extension of the transition cost amortization period for OE from 2006 to 2007; for CEI from 2008 to 2009 and for TE from mid-2007 to 2008;
	•		Deferral of interest costs on the accumulated shopping incentives and other cost deferrals as new regulatory assets; and
	•		Ability to initiate a request to increase generation rates under certain limited conditions.

          On February 23, 2004, after consideration of the PUCO Staff comments and testimony as well as those provided by some of the intervening parties, the Ohio Companies made certain modifications to the Rate Stabilization Plan. On June 9, 2004, the PUCO issued an order approving the revised Rate Stabilization Plan, subject to conducting a competitive bid process on or before December 1, 2004. In addition to requiring the competitive bid process, the PUCO made other modifications to the Ohio Companies’ revised Rate Stabilization Plan application. Among the major modifications were the following:

	•		Limiting the ability of the Ohio Companies to request adjustments in generation charges during 2006 through 2008 for increases in taxes;
	•		Expanding the availability of market support generation;
	•		Revising the kilowatt-hour target level and the time period for recovering regulatory transition charges;
	•		Establishing a 3-year competitive bid process for generation;

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	•		Establishing the 2005 generation credit for shopping customers, which would be extended as a cap through 2008; and
	•		Denying the ability to defer costs for future recovery of distribution reliability improvement expenditures.

          On June 18, 2004, the Ohio Companies filed with the PUCO an application for rehearing of the modified version of the Rate Stabilization Plan. Several other parties also filed applications for rehearing. On August 4, 2004, the PUCO issued an Entry on Rehearing modifying its June 9, 2004 Order. The modifications included the following:

	•		Expanding the Ohio Companies’ ability to request adjustments in generation charges during 2006 through 2008 to include increases in the cost of fuel (including the cost of emission allowances consumed, lime, stabilizers and other additives and fuel disposal) using 2002 as the base year. Any increases in fuel costs would be subject to downward adjustments in subsequent years should fuel costs decline, but not below the generation rate initially established in the Rate Stabilization Plan;
	•		Approving the revised kilowatt-hour target level and time period for recovery of regulatory transition costs as presented by the Ohio Companies in their rehearing application;
	•		Retaining the requirement for expanded availability of market support generation, but adopting the Ohio Companies’ alternative approach that conditions expanded availability on higher pricing and eliminating the requirement to reduce the interest deferral for certain affected rate schedules;
	•		Revising the calculation of the shopping credit cap for certain commercial and small industrial rate schedules; and
	•		Relaxing the notice requirement for availability of enhanced shopping credits in a number of instances.

          On August 5, 2004, the Ohio Companies accepted the Rate Stabilization Plan as modified and approved by the PUCO on August 4, 2004. The Ohio Companies retain the right to withdraw the modified Rate Stabilization Plan should subsequent adverse action be taken by the PUCO or a court. In the second quarter of 2004, the Ohio Companies implemented the accounting modifications contained in the PUCO’s June 9, 2004 Order, which are consistent with the PUCO’s August 4, 2004 Entry on Rehearing. Those modifications included amortization of transition costs based on extended amortization periods (that are no later than 2007 for OE, mid-2009 for CEI and mid-2008 for TE) and the deferral of interest costs on the accumulated deferred shopping incentives. On October 1, 2004, the OCC filed an appeal with the Ohio Supreme Court to overturn the June 9, 2004 PUCO order.

          The Ohio Companies filed a proposed competitive bid process which the PUCO modified on October 6, 2004. The PUCO approved the rules for the competitive bid process setting a three-year supply period (2006-2008) requirement for generation service suppliers and a load cap for individual suppliers. In mid-October, the initial auction schedule was revised so that Part 1 and Part 2 auction bidder applications are due November 4, 2004 and November 15, respectively, the trial auction is scheduled to occur on December 3, the auction would commence December 8 and the PUCO will accept or reject auction results within two business days after the completion of the auction. FirstEnergy has elected to not participate in the auction.

     Transition Cost Amortization

          OE, CEI and TE amortize transition costs (see Regulatory Matters – Ohio) using the effective interest method. Under the Rate Stabilization Plan as approved above, total transition cost amortization is expected to approximate the following for 2004 through 2009:

          The Ohio Companies are deferring customer shopping incentives and interest costs as new regulatory assets in accordance with the transition and rate stabilization plans. These regulatory assets totaling $556 million as of September 30, 2004 (OE - $205 million, CEI - $271 million, TE - $80 million) will be recovered through a surcharge rate equal to the RTC rate in effect when the transition costs have been fully recovered. Recovery of the new regulatory

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assets will begin at that time and amortization of the regulatory assets for each accounting period will be equal to the surcharge revenue recognized in each period.

     New Jersey

          JCP&L’s 2001 Final Decision and Order (Final Order) with respect to its rate unbundling, stranded cost and restructuring filings confirmed rate reductions set forth in its 1999 Summary Order, which had been in effect at increasing levels through July 2003. The Final Order also confirmed the establishment of a non-bypassable SBC to recover costs which include nuclear plant decommissioning and manufactured gas plant remediation, as well as a non-bypassable MTC primarily to recover stranded costs. The NJBPU has deferred making a final determination of the net proceeds and stranded costs related to prior generating asset divestitures until JCP&L’s request for an IRS ruling regarding the treatment of associated federal income tax benefits is acted upon. Should the IRS ruling support the return of the tax benefits to customers, there would be no effect to FirstEnergy’s or JCP&L’s net income since the contingency existed prior to the merger and there would be an adjustment to goodwill.

          In addition, the Final Order provided for the ability to securitize stranded costs associated with the divested Oyster Creek Nuclear Generating Station. Under NJBPU authorization in 2002, JCP&L issued through its wholly owned subsidiary, JCP&L Transition, $320 million of transition bonds (recognized as long-term debt on FirstEnergy’s and JCP&L’s Consolidated Balance Sheets) which securitized the recovery of these costs and which provided for a usage-based non-bypassable TBC to cover debt service on the bonds.

          Prior to August 1, 2003, JCP&L’s PLR obligation to provide BGS to non-shopping customers was supplied almost entirely from contracted and open market purchases. JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under NUG agreements exceed amounts collected through BGS and MTC rates. As of September 30, 2004, the accumulated deferred cost balance totaled approximately $404 million, after the charge discussed below. The NJBPU also allowed securitization of JCP&L’s deferred balance to the extent permitted by law upon application by JCP&L and a determination by the NJBPU that the conditions of the New Jersey restructuring legislation are met. There can be no assurance as to the extent, if any, that the NJBPU will permit such securitization.

          Under New Jersey transition legislation, all electric distribution companies were required to file rate cases to determine the level of unbundled rate components to become effective August 1, 2003. JCP&L’s two August 2002 rate filings requested increases in base electric rates of approximately $98 million annually and requested the recovery of deferred energy costs that exceeded amounts being recovered under the current MTC and SBC rates; one proposed method of recovery of these costs is the securitization of the deferred balance. This securitization methodology is similar to the Oyster Creek securitization. On July 25, 2003, the NJBPU announced its JCP&L base electric rate proceeding decision, which reduced JCP&L’s annual revenues by approximately $62 million effective August 1, 2003. The NJBPU decision also provided for an interim return on equity of 9.5% on JCP&L’s rate base for the subsequent six to twelve months. During that period, the decision also required that, within approximately one year of its issuance, JCP&L would initiate another proceeding to request recovery of additional costs incurred to enhance system reliability. In that Phase II proceeding, the NJBPU could increase JCP&L’s return on equity to 9.75% or decrease it to 9.25%, depending on its assessment of the reliability of JCP&L’s service. Any reduction would be retroactive to August 1, 2003. The net revenue decrease from the NJBPU’s decision consists of a $223 million decrease in the electricity delivery charge, a $111 million increase due to the August 1, 2003 expiration of annual customer credits previously mandated by the New Jersey transition legislation, a $49 million increase in the MTC tariff component, and a net $1 million increase in the SBC. The decision in the deferred balances proceeding disallowed $153 million of deferred energy costs, so that the MTC allows for the recovery of $465 million in deferred energy costs over the next ten years on an interim basis. As a result, JCP&L recorded charges to net income for the year ended December 31, 2003, aggregating $185 million ($109 million net of tax) consisting of the $153 million of disallowed deferred energy costs and $32 million of other disallowed regulatory assets. JCP&L filed an interim motion for rehearing and reconsideration with the NJBPU on August 15, 2003 with respect to the following issues: (1) the disallowance of the $153 million deferred energy costs; (2) the reduced rate of return on equity; and (3) $42.7 million of disallowed costs to achieve merger savings. In its final decision and order issued on May 17, 2004, the NJPBU clarified the method for calculating interest attributable to the cost disallowances, resulting in a $5.4 million reduction from the amount estimated in 2003. On June 1, 2004, JCP&L filed with the NJBPU a supplemental and amended motion for rehearing and reconsideration. On July 7, 2004, the NJBPU granted limited reconsideration and rehearing on the following issues: (1) deferred cost disallowances, (2) the capital structure including the rate of return, (3) merger savings, including amortization of costs to achieve merger savings; and (4) decommissioning. All other issues included in JCP&L’s amended motion were denied. Oral arguments were held on August 4, 2004. Management is unable to predict when a decision may be reached by the NJBPU.

          On July 5, 2003, JCP&L experienced a series of 34.5 kilovolt sub-transmission line faults that resulted in outages on the New Jersey shore. The NJBPU instituted an investigation into these outages, and directed that a Special Reliability Master (SRM) be hired to oversee the investigation. On December 8, 2003, the SRM issued his Interim Report recommending that JCP&L implement a series of actions to improve reliability in the area affected by the outages. The

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NJBPU adopted the findings and recommendations of the Interim Report on December 17, 2003, and ordered JCP&L to implement the recommended actions on a staggered basis, with initial actions to be completed by March 31, 2004. In late 2003, in accordance with a Settlement Stipulation concerning an August 2002 storm outage, the NJBPU engaged Booth & Associates to conduct an audit of the planning, operations and maintenance practices, policies and procedures of JCP&L. The audit was expanded to include the July 2003 outage and was completed in January 2004. On June 9, 2004, the NJBPU approved a stipulation that incorporated the final SRM report and portions of the final Booth report. The final order was issued by the NJBPU on July 23, 2004.

          On July 16, 2004, JCP&L filed the Phase II rate filing with the NJBPU which requested an increase in base rates of $36 million, reflecting the recovery of system reliability costs and a 9.75% return on equity. The filing also requests an increase to the MTC deferred balance recovery of approximately $20 million annually. Discovery/settlement conferences are ongoing. The filing fulfills the NJBPU requirement that a Phase II proceeding be conducted and that any expenditures and projects undertaken by JCP&L to increase its system reliability be reviewed.

          JCP&L sells all self-supplied energy (NUGs and owned generation) to the wholesale market with offsetting credits to its deferred energy balances with the exception of 300 MW from JCP&L’s must run NUG committed supply currently being used to serve BGS customers pursuant to NJBPU order. The BGS auction for periods beginning June 1, 2004 was completed in February 2004 and new BGS tariffs reflecting the auction results became effective June 1, 2004. On May 25, 2004, the NJBPU issued an order adopting a schedule for the BGS post transition year three process. JCP&L filed its proposal suggesting how BGS should be procured for year three and beyond. The NJBPU decision on the filing was announced on October 22, 2004, approving with minor modifications the BGS procurement process filed by JCP&L and the other New Jersey electric distribution companies and authorizing the continued use of NUG committed supply to serve 300 MW of BGS load. The auction is scheduled to take place in February 2005 for the supply period beginning June 1, 2005.

          In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004 supporting a continuation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey ratepayers without a reduction, termination or capping of the funding. On September 30, 2004, JCP&L filed an updated TMI-2 decommissioning study prepared by TLG Services, Inc. (see Note 2 — Asset Retirement Obligations). This study resulted in an updated total decommissioning cost estimate of $729 million (in 2003 dollars) compared to the estimated $528 million (in 2003 dollars) from the prior 1995 decommissioning study.

     Pennsylvania

          The PPUC authorized in 1998 rate restructuring plans for Penn, Met-Ed and Penelec. In 2000, the PPUC disallowed a portion of the requested additional stranded costs above those amounts granted in Met-Ed’s and Penelec’s 1998 rate restructuring plan orders. The PPUC required Met-Ed and Penelec to seek an IRS ruling regarding the return of certain unamortized investment tax credits and excess deferred income tax benefits to customers. Similar to JCP&L’s situation, if the IRS ruling ultimately supports returning these tax benefits to customers, there would be no effect to FirstEnergy’s, Met-Ed’s or Penelec’s net income since the contingency existed prior to the merger and would be an adjustment to goodwill.

          In June 2001, the PPUC approved the Settlement Stipulation with all of the major parties in the combined merger and rate relief proceedings which approved the FirstEnergy/GPU merger and provided PLR deferred accounting treatment for energy costs, permitting Met-Ed and Penelec to defer, for future recovery, energy costs in excess of amounts reflected in their capped generation rates retroactive to January 1, 2001. This PLR deferral accounting procedure was later denied in a February 2002 Commonwealth Court of Pennsylvania decision. The court decision also affirmed the PPUC decision regarding approval of the merger, remanding the decision to the PPUC only with respect to the issue of merger savings. FirstEnergy established reserves in 2002 for Met-Ed’s and Penelec’s PLR deferred energy costs which aggregated $287.1 million, reflecting the potential adverse impact of the then pending Pennsylvania Supreme Court decision whether to review the Commonwealth Court decision. As a result, FirstEnergy recorded in 2002 an aggregate non-cash charge of $55.8 million ($32.6 million net of tax) to income for the deferred costs incurred subsequent to the merger. The reserve for the remaining $231.3 million of deferred costs increased goodwill by an aggregate net of tax amount of $135.3 million.

          On April 2, 2003, the PPUC remanded the issue relating to merger savings to the Office of Administrative Law for hearings, directed Met-Ed and Penelec to file a position paper on the effect of the Commonwealth Court order on the Settlement Stipulation and allowed other parties to file responses to the position paper. Met-Ed and Penelec filed a letter with the ALJ on June 11, 2003, voiding the Settlement Stipulation in its entirety and reinstating Met-Ed’s and Penelec’s restructuring settlement previously approved by the PPUC.

          On October 2, 2003, the PPUC issued an order concluding that the Commonwealth Court reversed the PPUC’s June 20, 2001 order in its entirety. The PPUC directed Met-Ed and Penelec to file tariffs within thirty days of the order to reflect the CTC rates and shopping credits that were in effect prior to the June 21, 2001 order to be effective

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upon one day’s notice. In response to that order, Met-Ed and Penelec filed supplements to their tariffs to become effective October 24, 2003.

          On October 8, 2003, Met-Ed and Penelec filed a petition for clarification relating to the October 2, 2003 order on two issues: to establish June 30, 2004 as the date to fully refund the NUG trust fund and to clarify that the ordered accounting treatment regarding the CTC rate/shopping credit swap should follow the ratemaking, and that the PPUC’s findings would not impair their rights to recover all of their stranded costs. On October 9, 2003, ARIPPA (an intervenor in the proceedings) petitioned the PPUC to direct Met-Ed and Penelec to reinstate accounting for the CTC rate/shopping credit swap retroactive to January 1, 2002. Several other parties also filed petitions. On October 16, 2003, the PPUC issued a reconsideration order granting the date requested by Met-Ed and Penelec for the NUG trust fund refund, denying Met-Ed’s and Penelec’s other clarification requests and granting ARIPPA’s petition with respect to the accounting treatment of the changes to the CTC rate/shopping credit swap. On October 22, 2003, Met-Ed and Penelec filed an Objection with the Commonwealth Court asking that the Court reverse the PPUC’s finding that requires Met-Ed and Penelec to treat the stipulated CTC rates that were in effect from January 1, 2002 on a retroactive basis.

          On October 27, 2003, a Commonwealth Court judge issued an Order denying Met-Ed’s and Penelec’s Objection without explanation. Due to the vagueness of the Order, Met-Ed and Penelec, on October 31, 2003, filed an Application for Clarification with the judge. Concurrent with this filing, Met-Ed and Penelec, in order to preserve their rights, also filed with the Commonwealth Court both a Petition for Review of the PPUC’s October 2 and October 16 Orders, and an application for reargument, if the judge, in his clarification order, indicates that Met-Ed’s and Penelec’s Objection was intended to be denied on the merits. In addition to these findings, Met-Ed and Penelec, in compliance with the PPUC’s Orders, filed revised PPUC quarterly reports for the twelve months ended December 31, 2001 and 2002, and for the first two quarters of 2003, reflecting balances consistent with the PPUC’s findings in their Orders.

          Met-Ed and Penelec purchase a portion of their PLR requirements from FES through a wholesale power sale agreement. The PLR sale is automatically extended for each successive calendar year unless any party elects to cancel the agreement by November 1 of the preceding year. Under the terms of the wholesale agreement, FES retains the supply obligation and the supply profit and loss risk, for the portion of power supply requirements not self-supplied by Met-Ed and Penelec under their NUG contracts and other power contracts with nonaffiliated third party 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. FES has hedged most of Met-Ed’s and Penelec’s unfilled PLR on-peak obligation through 2004 and a portion of 2005, the period during which deferred accounting was previously allowed under the PPUC’s order. Met-Ed and Penelec are authorized to continue deferring differences between NUG contract costs and current market prices.

7 - NEW ACCOUNTING STANDARDS AND INTERPRETATIONS:

Exposure Draft of Proposed Statement of Financial Accounting Standards – Share-Based Payment – an amendment of FASB Statements No. 123 and 95

          In March 2004, the FASB issued an exposure draft of a new standard, which would amend SFAS 123 and SFAS 95. Among other items, the new standard would require expensing stock options in FirstEnergy’s financial statements. In October 2004, the FASB agreed to delay the effective date of the proposed standard from January 1, 2005 to periods beginning after June 15, 2005, for calendar year companies. FirstEnergy will not be able to determine the impact of the proposed standard on its results of operations until the standard is issued in final form. The impacts of the fair value recognition provisions of SFAS 123 on FirstEnergy’s net income and earnings per share for the current reporting periods are disclosed in Note 2.

Exposure Draft of Proposed Statement of Financial Accounting Standards – Earnings per Share – an amendment of FASB Statement No. 128

          In December 2003, the FASB issued an exposure draft of a new standard, which would amend SFAS 128. Among other items, the new standard would eliminate the provisions of SFAS 128 that allow an entity to rebut the presumption that contracts with the option of settling in either cash or stock will be settled in stock. The new standard is expected to be issued in the fourth quarter of 2004 and be effective for all periods ending after December 15, 2004. Retrospective application to all prior-period earnings per share data presented would be required. FirstEnergy is continuing to assess the proposed standard but does not anticipate a material impact on its calculation of earnings per share.

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EITF Issue No. 03-1, “The Meaning of Other-Than-Temporary and Its Application to Certain Investments”

          In March 2004, the EITF reached a consensus on the application guidance for Issue 03-1. EITF 03-1 provides a model for determining when investments in certain debt and equity securities are considered other than temporarily impaired. When an impairment is other-than-temporary, the investment must be measured at fair value and the impairment loss recognized in earnings. The recognition and measurement provisions of EITF 03-1, which were to be effective for periods beginning after June 15, 2004, were delayed by the issuance of FSP EITF 03-1-1 in September 2004. During the period of delay, FirstEnergy will continue to evaluate its investments as required by existing authoritative guidance.

EITF Issue No. 03-16, “Accounting for Investments in Limited Liability Companies”

          In March 2004, the FASB ratified the final consensus on Issue 03-16. EITF 03-16 requires that an investment in a limited liability company that maintains a “specific ownership account” for each investor should be viewed as similar to an investment in a limited partnership for determining whether the cost or equity method of accounting should be used. The equity method of accounting is generally required for investments that represent more than a three to five percent interest in a limited partnership. EITF 03-16 was adopted by FirstEnergy in the third quarter of 2004 and did not affect the Companies’ financial statements.

FSP 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003”

          Issued in May 2004, FSP 106-2 provides guidance on accounting for the effects of the Medicare Act for employers that sponsor postretirement health care plans that provide prescription drug benefits. FSP 106-2 also requires certain disclosures regarding the effect of the federal subsidy provided by the Medicare Act. The effect of the federal subsidy provided under the Medicare Act on FirstEnergy’s consolidated financial statements is described in Note 4. The impact of the subsidy was not material to the financial statements of each of the Companies for the three and nine months ended September 30, 2004.

FIN 46 (revised December 2003), “Consolidation of Variable Interest Entities”

          In December 2003, the FASB issued a revised interpretation of ARB 51 referred to as FIN 46R, which requires the consolidation of a VIE by an enterprise if that enterprise is determined to be the primary beneficiary of the VIE. As required, FirstEnergy adopted FIN 46R for interests in VIEs commonly referred to as special-purpose entities effective December 31, 2003 and for all other types of entities effective March 31, 2004. Adoption of FIN 46R did not have a material impact on the consolidated financial statements of FirstEnergy or the Companies.

8 - SEGMENT INFORMATION:

          FirstEnergy operates under two reportable segments: regulated services and competitive services. The aggregate “Other” segments do not individually meet the criteria to be considered a reportable segment. “Other” consists of interest expense related to holding company debt; corporate support services and the international businesses acquired in the 2001 merger. FirstEnergy’s primary segment is its regulated services segment, whose operations include the regulated sale of electricity and distribution and transmission services by its eight EUOC in Ohio, Pennsylvania and New Jersey. The competitive services business segment consists of the subsidiaries (FES, FSG, MYR and FirstCom) that operate unregulated energy and energy-related businesses, including the operation of FirstEnergy’s generation facilities resulting from the deregulation of the Companies’ electric generation business (see Note 6 – Regulatory Matters). The regulated services segment designs, constructs, operates and maintains FirstEnergy’s regulated transmission and distribution systems. Its revenues are primarily derived from electricity delivery and transition costs recovery.

          The competitive services segment has responsibility for FirstEnergy generation operations as discussed under Note 6. As a result, its revenues include all generation electric sales revenues (including the generation services to regulated franchise customers who have not chosen an alternative generation supplier) and all domestic unregulated energy and energy-related services including commodity sales (both electricity and natural gas) in the retail and wholesale markets, marketing, generation and sourcing of commodity requirements, providing local and long-distance phone service, as well as other competitive energy-application services.

          Segment reporting in 2003 was reclassified to conform with the current year business segment organizations and operations. Revenues from the competitive services segment now include all generation revenues including generation services to regulated franchise customers previously reported under the regulated services segment and now exclude revenues from power supply agreements with the regulated services segment previously reported as internal revenues. The regulated services segment results now exclude generation sales revenues and related generation commodity costs. Certain amounts (including transmission and congestion charges) were reclassified among purchased

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power, other operating costs and depreciation and amortization to conform with the current year presentation of generation commodity costs. Segment results for 2003 have been adjusted to reflect the reclassification of revenue, expense, interest expense and tax amounts of divested businesses reflected as discontinued operations (see Note 2) and certain revenues and expenses have been reclassified and presented on a net basis to conform with the current year presentation (see Note 1).

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Segment Financial Information