10-Q 1 main.txt UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549 FORM 10-Q (Mark One) [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended June 30, 2004 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to ---------------- ------------------ Commission Registrant; State of Incorporation; I.R.S. Employer File Number Address; and Telephone Number Identification No. ----------- ----------------------------- ------------------ 333-21011 FIRSTENERGY CORP. 34-1843785 (An Ohio Corporation) 76 South Main Street Akron, OH 44308 Telephone (800)736-3402 1-2578 OHIO EDISON COMPANY 34-0437786 (An Ohio Corporation) 76 South Main Street Akron, OH 44308 Telephone (800)736-3402 1-2323 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY 34-0150020 (An Ohio Corporation) c/o FirstEnergy Corp. 76 South Main Street Akron, OH 44308 Telephone (800)736-3402 1-3583 THE TOLEDO EDISON COMPANY 34-4375005 (An Ohio Corporation) c/o FirstEnergy Corp. 76 South Main Street Akron, OH 44308 Telephone (800)736-3402 1-3491 PENNSYLVANIA POWER COMPANY 25-0718810 (A Pennsylvania Corporation) c/o FirstEnergy Corp. 76 South Main Street Akron, OH 44308 Telephone (800)736-3402 1-3141 JERSEY CENTRAL POWER & LIGHT COMPANY 21-0485010 (A New Jersey Corporation) c/o FirstEnergy Corp. 76 South Main Street Akron, OH 44308 Telephone (800)736-3402 1-446 METROPOLITAN EDISON COMPANY 23-0870160 (A Pennsylvania Corporation) c/o FirstEnergy Corp. 76 South Main Street Akron, OH 44308 Telephone (800)736-3402 1-3522 PENNSYLVANIA ELECTRIC COMPANY 25-0718085 (A Pennsylvania Corporation) c/o FirstEnergy Corp. 76 South Main Street Akron, OH 44308 Telephone (800)736-3402 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): Yes X No FirstEnergy Corp. --- ----- Yes No X 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 Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: OUTSTANDING CLASS AS OF AUGUST 6, 2004 ----- -------------------- FirstEnergy Corp., $.10 par value 329,836,276 Ohio Edison Company, no par value 100 The Cleveland Electric Illuminating Company, no par value 79,590,689 The Toledo Edison Company, $5 par value 39,133,887 Pennsylvania Power Company, $30 par value 6,290,000 Jersey Central Power & Light Company, $10 par value 15,371,270 Metropolitan Edison Company, no par value 859,500 Pennsylvania Electric Company, $20 par value 5,290,596 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 outage and the outcome, cost and other effects of present and potential legal and administrative proceedings and claims related to that outage, with respect to FirstEnergy Corp. and the Ohio registrants, the final outcome in the proceeding related to the registrants' Application for a Rate Stabilization Plan, 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.

GLOSSARY OF TERMS The following abbreviations and acronyms are used in this report to identify FirstEnergy Corp. and its current and former subsidiaries: ATSI.....................American Transmission Systems, Inc., owns and operates transmission facilities Avon.....................Avon Energy Partners Holdings CEI......................The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary CFC......................Centerior Funding Corporation, a wholly owned finance subsidiary of CEI Companies................OE, CEI, TE, Penn, JCP&L, Met-Ed and Penelec Emdersa ................ Empresa Distribuidora Electrica Regional S.A EUOC.....................Electric Utility Operating Companies, (OE, CEI, TE, Penn, JCP&L, Met-Ed, Penelec, ATSI) FENOC....................FirstEnergy Nuclear Operating Company, operates nuclear generating facilities FES......................FirstEnergy Solutions Corp., provides energy-related products and services FESC.....................FirstEnergy Service Company, provides legal, financial, and other corporate support services FGCO.....................FirstEnergy Generation Corp., operates nonnuclear generating facilities FirstCom.................First Communications, LLC, provides local and long-distance phone service FirstEnergy..............FirstEnergy Corp., a registered public utility holding company FSG......................FirstEnergy Facilities Services Group, LLC, the parent company of several heating, ventilation air conditioning and energy management companies GLEP.....................Great Lakes Energy Partners, LLC, an oil and natural gas exploration and production venture GPU......................GPU, Inc., former parent of JCP&L, Met-Ed and Penelec, which merged with FirstEnergy on November 7, 2001 GPU Capital..............GPU Capital, Inc., owned and operated electric distribution systems in foreign countries GPU Power................GPU Power, Inc., owned and operated generation facilities in foreign countries GPUS.....................GPU Service Company, previously provided corporate support services JCP&L....................Jersey Central Power & Light Company, a New Jersey electric utility operating subsidiary JCP&L Transition.........JCP&L Transition Funding LLC, a Delaware limited liability company and issuer of transition bonds MARBEL...................MARBEL Energy Corporation, previously held FirstEnergy's interest in GLEP Met-Ed...................Metropolitan Edison Company, a Pennsylvania electric utility operating subsidiary MYR......................MYR Group, Inc., a utility infrastructure construction service company NEO......................Northeast Ohio Natural Gas Corp., formerly a MARBEL subsidiary OE.......................Ohio Edison Company, an Ohio electric utility operating subsidiary OE Companies.............OE and Penn Penelec..................Pennsylvania Electric Company, a Pennsylvania electric utility operating subsidiary Penn.....................Pennsylvania Power Company, a Pennsylvania electric utility operating subsidiary of OE PNBV.....................PNBV Capital Trust, a special purpose entity created by OE in 1996 Shippingport.............Shippingport Capital Trust, a special purpose entity created by CEI and TE in 1997 TE.......................The Toledo Edison Company, an Ohio electric utility operating subsidiary TEBSA....................Termobarranquilla S.A., Empresa de Servicios Publicos TECC.....................Toledo Edison Capital Corporation, a 90% owned subsidiary of TE The following abbreviations and acronyms are used to identify frequently used terms in this report: ALJ......................Administrative Law Judge AOCL.....................Accumulated Other Comprehensive Loss APB......................Accounting Principles Board APB 25...................APB Opinion No. 25, "Accounting for Stock Issued to Employees" ARB 51...................Accounting Research Bulletin No. 51, "Consolidated Financial Statements" ARO......................Asset Retirement Obligation ASLB.....................Atomic Safety and Licensing Board BGS......................Basic Generation Service CO2......................Carbon Dioxide CTA......................Currency Translation Adjustment CTC......................Competitive Transition Charge ECAR.....................East Central Area Reliability Agreement EITF.....................Emerging Issues Task Force EITF 03-1................EITF Issue No. 03-1, "The Meaning of Other-Than- Temporary and Its Application to Certain Investments" EITF 03-6................EITF Issue No. 03-6, "Participating Securities and the Two-Class Method Under Financial Accounting Standards Board Statement No. 128, Earnings per Share" EITF 99-19...............EITF Issue No. 99-19, "Reporting Revenue Gross as a Principal versus Net as an Agent" i EPA......................Environmental Protection Agency FASB.....................Financial Accounting Standards Board FCON 7...................FASB Concepts Statement No. 7, "Using Cash Flow Information and Present Value in Accounting Measurements" FERC.....................Federal Energy Regulatory Commission FIN .....................FASB Interpretation FIN 46R..................FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities" FMB......................First Mortgage Bonds FSP......................FASB Staff Position FSP 106-1................FASB Staff Position 106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003" FSP 106-2................FASB Staff Position 106-2, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003" GAAP.....................Accounting Principles Generally Accepted in the United States HVAC.....................Heating, Ventilation and Air-conditioning IRS......................Internal Revenue Service ISO......................Independent System Operator KWH......................Kilowatt-hours LOC......................Letter of Credit MACT.....................Maximum Achievable Control Technologies Medicare Act.............Medicare Prescription Drug, Improvement and Modernization Act of 2003 MISO.....................Midwest Independent System Operator, Inc. Moody's..................Moody's Investors Service MTC......................Market Transition Charge MTN......................Medium Term Note MW.......................Megawatts NAAQS....................National Ambient Air Quality Standards NERC.....................North American Electric Reliability Council NJBPU....................New Jersey Board of Public Utilities NOV......................Notices of Violation NOX......................Nitrogen Oxide NRC......................Nuclear Regulatory Commission NUG......................Non-Utility Generation OCI......................Other Comprehensive Income OPEB.....................Other Post-Employment Benefits PJM......................PJM Interconnection ISO PLR......................Provider of Last Resort PPUC.....................Pennsylvania Public Utility Commission PRP......................Potentially Responsible Party PUCO.....................Public Utilities Commission of Ohio S&P......................Standard & Poor's SBC......................Societal Benefits Charge SEC......................United States Securities and Exchange Commission SFAS.....................Statement of Financial Accounting Standards SFAS 71..................SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation" SFAS 87..................SFAS No. 87, "Employers' Accounting for Pensions" SFAS 95..................SFAS No. 95, "Statement of Cash Flows" SFAS 106.................SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" SFAS 123.................SFAS No. 123, "Accounting for Stock-Based Compensation" SFAS 133.................SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" SFAS 140.................SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities" SFAS 142.................SFAS No. 142, "Goodwill and Other Intangible Assets" SFAS 143.................SFAS No. 143, "Accounting for Asset Retirement Obligations" SFAS 144.................SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" SFAS 150.................SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity" SO2......................Sulfur Dioxide SPE......................Special Purpose Entity TBC......................Transition Bond Charge TMI-2....................Three Mile Island Unit 2 VIE......................Variable Interest Entity ii 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 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) 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. These utility subsidiaries are referred to throughout as "EUOC." The utility subsidiaries excluding ATSI, which is not a registrant, are referred to throughout as the "Companies." 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). 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 Public Company Accounting Oversight Board (United States). 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. 1 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 beneficiary 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 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 with OE's 1987 sale and leaseback transactions involving 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. Consolidation of PNBV by FirstEnergy and OE as of December 31, 2003 changed the 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 by the owner trusts in CEI's and TE's Bruce Mansfield Plant sale and leaseback transaction in 1987. CEI and TE acquired all of 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 June 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 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 $680 million, $111 million and $561 million, respectively, that would not be payable if the casualty value payments are made. As of June 30, 2004, CEI and TE have recorded above-market lease obligations related to the Bruce Mansfield Plant and Beaver Valley Unit 2 totaling $1.1 billion (CEI - $759 million and TE - $305 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 respective 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% trust preferred securities (aggregate value $100 million). On July 30, 2004, Penelec announced that it will redeem 100% of its affiliated trust's 7.34% preferred securities (aggregate value of $100 million) effective September 1, 2004. Penelec has effectively provided a full and unconditional guarantee of obligations under the trust's preferred securities. 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 June 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 an EUOC and the contract price for power is 2 correlated with the plant's variable costs of production. FirstEnergy, through its subsidiaries JCP&L, Met-Ed and 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. FirstEnergy has requested but not received the information necessary to determine whether these nine entities are VIEs or whether JCP&L, Met-Ed or Penelec is the primary beneficiary. In most cases, the requested information was deemed 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 and six months ended June 30, 2004 and 2003 were as follows: Three Months Ended Six Months Ended June 30, June 30, ----------------------------------------------- 2004 2003 2004 2003 ------------------------------------------------------------------------------ (In millions) JCP&L................... $35 $25 $ 63 $58 Met-Ed.................. 9 11 25 27 Penelec................. 6 6 13 13 --- --- ---- --- Total................ $50 $42 $101 $98 === === ==== === 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 agreements were exercised. Stock-based awards to purchase shares of common stock totaling 3.3 million in each of the second quarter and first six months of 2004 and 0.5 million and 3.5 million in the second quarter and first six months of 2003, respectively, 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. The following table reconciles the denominators for basic and diluted earnings per share from Income Before Discontinued Operations and Cumulative Effect of Accounting Change:

3 Preferred Stock Subject to Mandatory Redemption Long-term debt includes the preferred stock of consolidated subsidiaries subject to mandatory redemption as of June 30, 2004 and December 31, 2003 in accordance with SFAS 150. This standard, issued in May 2003, 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 effective July 1, 2003 had no impact on FirstEnergy's Consolidated Statements of Income because the preferred dividends 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 quarter and six months ended June 30, 2003, but have included the dividends in interest charges for the quarter and six months ended June 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. FirstEnergy uses derivatives to hedge the risk of price and interest rate fluctuations. 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. Gains and losses from hedges of commodity price risks are included in net income when the underlying hedged commodities are delivered. Also, the ineffective portion of hedge gains and losses is included in net income. 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 hedges of anticipated interest payments on acquisition debt are included in net income over the periods that hedged interest payments are made - 5, 10 and 30 years. Gains and losses from derivative contracts are included in other operating expenses. The net deferred loss included in AOCL as of June 30, 2004 and March 31, 2004 was $100 million and $111 million, respectively. The decrease resulted from the sale of GLEP (see Note 5). Approximately $11 million (after tax) of the net deferred loss on derivative instruments in AOCL as of June 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. During the second quarter of 2004, FirstEnergy executed fixed-for-floating interest rate swap agreements with an aggregate notional amount of $350 million, whereby FirstEnergy receives fixed cash flows based on the fixed coupons of the hedged securities and pays variable cash flows based on short-term variable market interest rates. These derivatives are treated as fair value hedges of fixed-rate, long-term debt issues - protecting 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. FirstEnergy entered into interest rate swap agreements on $350 million notional amount of its subsidiaries' senior notes and subordinated debentures having a weighted average fixed interest rate of 5.89%; the interest rate swap agreements have effectively converted that 4 rate to a current weighted average variable rate of 2.42%. The notional values of interest rate swap agreements increased to $1.70 billion as of June 30, 2004 from $1.15 billion as of December 31, 2003. 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. As of June 30, 2004, FirstEnergy had $6.1 billion of goodwill that primarily relates to its regulated services segment. In the first six 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 six months ended June 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 $1.217 billion as of June 30, 2004 and included $1.203 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. The Companies maintain nuclear decommissioning trust funds that are legally restricted for purposes of settling the nuclear decommissioning ARO. As of June 30, 2004, the fair value of the decommissioning trust assets was $1.425 billion. Under the current terms of the plants' operating licenses, payments for decommissioning of the nuclear generating units would begin in 2014, when actual decommissioning work would begin. 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 six months ended June 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 on the grant date and would be effective for FirstEnergy and the Companies on January 1, 2005. FirstEnergy will not be able to determine the exact 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.

Discontinued Operations FirstEnergy's discontinued operations in the second quarter and the first six months of 2003 consisted of net losses aggregating $68 million and $66 million, respectively, from its Argentina and Bolivia international 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 six months ended June 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 6 of common stock), partially offset by the gain recognized from abandoning FirstEnergy's investment in Emdersa ($22 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 $22 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 asset retirement costs of $602 million as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $415 million. The ARO liability on the date of adoption was $1.11 billion, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. The remaining cumulative effect adjustment for unrecognized depreciation and accretion, offset by the reduction in the existing decommissioning liabilities and the reversal of accumulated estimated removal costs for non-regulated generation assets, was a $175 million increase to income, $102 million net of tax, or $0.35 per share of common stock (basic and diluted) in the three months and six months ended June 30, 2003. 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:

Restatements of TE, JCP&L and Penelec Previously Reported Quarterly Results Earnings for the three months and six months ended June 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 $0.6 million ($0.3 million after-tax) and $1.0 million ($0.6 million after-tax) in the second quarter and the first six months of 2003, respectively. TE's interest expense was overstated by $0.3 million ($0.2 million after-tax) and $1.3 million ($0.7 million after-tax) in the second quarter and the first six months of 2003, respectively. Similar to TE, JCP&L's capital costs originally recorded as operating expenses were $3.0 million ($1.8 million after-tax) and $3.2 million ($1.9 million after-tax) in the second quarter and the first six months of 2003, respectively. Penelec's capital costs originally recorded as operating expenses were $0.7 million ($0.4 million after-tax) in the second quarter and the first six months of 2003. 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 six months ended June 30, 2003 are as follows: 7

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 $708 million (OE-$108 million, CEI-$91 million, TE-$48 million, Penn-$64 million, JCP&L-$142 million, Met-Ed-$53 million, Penelec-$60 million, ATSI-$24 million, FES-$81 million and other subsidiaries-$37 million) is applicable to 2004. Investments for additional nuclear fuel during the 2004-2006 period are estimated to be approximately $300 million (OE-$84 million, CEI-$98 million, TE-$63 million and Penn-$55 million), of which approximately $82 million (OE-$26 million, CEI-$26 million, TE-$11 million and Penn-$19 million) applies to 2004. 8 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 June 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 that such parental guarantees of $0.9 billion (included in the $1.0 billion discussed above) as of June 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 is remote. 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 June 30, 2004:

Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related FirstEnergy guarantees of $257 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. FirstEnergy has also guaranteed the obligations of the operators of the TEBSA project in Colombia, up to a maximum of $6 million (subject to escalation) under the project's operations and maintenance agreement. In connection with the sale of TEBSA in January 2004, the purchaser indemnified FirstEnergy against any loss under this guarantee. FirstEnergy has provided the TEBSA project lenders a $60 million letter of credit, which is renewable and declines yearly based upon the senior outstanding debt of TEBSA. This LOC granted FirstEnergy the ability to sell its remaining 20.1% interest in Avon (parent of Midlands Electricity in the United Kingdom). 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 9 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. NOx 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 NOx reductions from the Companies' facilities. The EPA's NOx Transport Rule imposes uniform reductions of NOx emissions (an approximate 85% reduction in utility plant NOx 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 NOx emissions are contributing significantly to ozone levels in the eastern United States. State Implementation Plans (SIP) were required to comply by May 31, 2004 with individual state NOx budgets. New Jersey and Pennsylvania submitted a SIP that required compliance with the state NOx 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 NOx budgets at the Companies' Michigan and Ohio facilities by May 31, 2004. The Companies believe their facilities are complying with the state NOx 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" NOx 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. NOx 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 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 NOx 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 a Compliance Order 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 10 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 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 June 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 be held liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of June 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 - $29,000, Penelec - $26,000, and other - $16.8 million) as of June 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. 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. Power Outages 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. Since July 1999, this litigation has involved a substantial amount of legal discovery including interrogatories, request for production of documents, preservation and inspection of evidence, and depositions of the named plaintiffs 11 and many JCP&L employees. In addition, there have been many motions filed and argued by the parties involving issues such as the primary jurisdiction and findings of the NJBPU, consumer fraud by JCP&L, strict product liability, class decertification, and the damages claimed by the plaintiffs. In January 2000, the NJ Appellate Division determined that the trial court has proper jurisdiction over this litigation. 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 July 28, 2004, both plaintiffs and JCP&L appealed the decision of the Appellate Division to the New Jersey Supreme Court. FirstEnergy is unable to predict the outcome of these matters and no liability has been accrued as of June 30, 2004. On August 14, 2003, various states and parts of southern Canada experienced a widespread power outage. That outage 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 this outage. In the final report, the Task Force concluded, among other things, that the problems leading to the outage began in FirstEnergy's Ohio service area. Specifically, the final report concludes, among other things, that the initiation of the August 14th power outage resulted from the coincidence on that afternoon of several events, including: 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 14th power outage and that it does not adequately address the underlying causes of the outage. FirstEnergy remains convinced that the outage cannot be explained by events on any one utility's system. 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 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 14th power outage, 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 June 30, 2004 for any expenditures in excess of those actually incurred through that date. Davis-Besse 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. As part of its informal inquiry, which began in September 2003, the SEC's Division of Enforcement requested on June 24, 2004 that FirstEnergy voluntarily provide information and documents related to the Davis-Besse outage. FirstEnergy is complying with this request and continues to cooperate fully with this inquiry. If it were ultimately determined that FirstEnergy has legal liability or is otherwise made subject to enforcement action based on any of the above matters with respect to the Davis-Besse outage, it could have a material adverse effect on FirstEnergy's financial condition and results of operations. 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. 12 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 its Ohio utility subsidiaries of previously reported results, the August 14th power outage 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 a charge against FirstEnergy's second quarter 2004 earnings of $0.03 per share of common stock. The federal securities cases were consolidated into a single action, as were the federal derivative cases; those actions are pending in federal court in Akron. Two state court derivative cases are also pending. The settlement is subject to court approval and, 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. FirstEnergy's Ohio utility subsidiaries were named as respondents in two regulatory proceedings initiated at the PUCO in response to complaints alleging failure to provide reasonable and adequate service stemming primarily from the August 14th power outage. FirstEnergy is vigorously defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against them. 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 outage. All three cases were dismissed for lack of jurisdiction. One case was refiled at the PUCO and the other two have been appealed. If FirstEnergy were ultimately determined to have legal liability in connection with the legal proceedings described above, it could have a material adverse effect on its 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:

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 six months ended June 30, 2004. The Company has no funding requirements for the remainder of 2004. FirstEnergy did not contribute to its pension plans during the first six months of 2004 and 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, 13 including amounts capitalized, recognized by each of the Companies in the three and six months ended June 30, 2004 were as follows:

The net periodic postretirement benefit costs, including amounts capitalized, recognized by each of the Companies in the three and six months ended June 30, 2004 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 six months ended June 30, 2004, by $13 million and $22 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 six months ended June 30, 2004, as follows:

The impact of the subsidy was not material to the financial statements of each of the Companies for the three and six months ended June 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 percent interest in Avon on January 16, 2004, and its 28.67 percent 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 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-percent 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. 14 6 - REGULATORY MATTERS: In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry deregulation contain similar provisions which are reflected in the Companies' respective state regulatory plans. However, despite these similarities, the specific approach taken by each state and for each of the Companies varies. These provisions include: o allowing the Companies' electric customers to select their generation suppliers; o establishing PLR obligations to non-shopping customers in the Companies' service areas; o allowing recovery of potentially stranded investment (or transition costs) not otherwise recoverable in a competitive generation market; o itemizing (unbundling) the price of electricity into its component elements - including generation, transmission, distribution and stranded costs recovery charges; o deregulating the Companies' electric generation businesses; o continuing regulation of the Companies' transmission and distribution systems; and o requiring corporate separation of regulated and unregulated business activities. Reliability Initiatives On October 15, 2003, NERC issued a letter to all NERC control areas and reliability coordinators requesting that a review of various reliability practices be undertaken within 60 days. The Company issued its response on December 15, 2003, confirming that its review had taken place and noted that it was undertaking various enhancements to current practices. On February 10, 2004, NERC issued its Recommended Actions to Prevent and Mitigate the Impacts of Future Cascading Blackouts. Approximately 20 of the recommendations were directed at the FirstEnergy companies and broadly focused on initiatives that were recommended for completion by June 30, 2004. These initiatives principally related to: changes in voltage criteria and reactive resources management; operational preparedness and action plans; emergency response capabilities; and preparedness and operating center training. FirstEnergy presented a detailed implementation plan to NERC, which the NERC Board of Trustees subsequently endorsed on May 7, 2004. The various initiatives required by NERC to be completed by June 30, 2004 have been certified as complete to NERC (on June 30, 2004), with one minor exception related to reactive testing of certain generators expected to be completed later this year. An independent NERC verification team conducted an on-site review of the completion status, reporting on July 14, 2004, that FirstEnergy had implemented the policies, procedures and actions that were recommended to be completed by June 30, 2004, with the exception noted by FirstEnergy. Implementation of the recommendations has not required incremental material investment or upgrades to existing equipment. On February 26 and 27, 2004, certain FirstEnergy companies participated in a NERC Control Area Readiness Audit. This audit, part of an announced program by NERC to review control area operations throughout much of the United States during 2004, was an independent review to identify areas recommended for reliability improvement. The final audit report was completed on May 6, 2004. The report identified positive observations and included various recommendations for reliability improvement. FirstEnergy implemented the audit results and recommendations relating to summer 2004 and 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 finalized later this year. 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 5, 2004, the U.S. - Canada Power System Outage Task Force issued a Final Report on the August 14, 2003 power outage. 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 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 recommendations on June 30, 2004. Implementation of the recommendations has not required incremental material investment or upgrades to existing equipment. 15 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 summer 2004 and 2009. FirstEnergy is continuing to review the results of that study related to 2009 and completed the implementation of recommendations relating to 2004 by June 30, 2004. Based on its review thus far, FirstEnergy believes that the study does not recommend any incremental material investment or upgrades to existing equipment. FirstEnergy notes, however, that 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. 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 thereafter assembled an independent verification team to confirm implementation of NERC Recommended Actions to Prevent and Mitigate the Impacts of Future Cascading Blackouts required to be completed by June 30, 2004, as well as NERC recommendations contained in the Control Area Readiness Audit Report required to be completed by summer 2004, and recommendations in the Joint U.S. Canada Power System Outage Task Force Report directed toward FirstEnergy and required to be completed by June 30, 2004. The NERC 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. On July 5, 2003, JCP&L experienced a series of 34.5 kilo-volt 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 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. JCP&L expects to spend $12.5 million implementing these actions during 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. JCP&L is awaiting the final NJBPU order. 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. Discovery has commenced in the proceeding and Met-Ed's, Penelec's and Penn's testimony was filed May 7, 2004. On June 21, 2004, intervenors filed rebuttal testimony and Met-Ed's, Penelec's and Penn's surrebuttal testimony was filed on July 23, 2004. Hearings were held in early August 2004 and the ALJ has been directed to issue a Recommended Decision by September 30, 2004, in order to allow the PPUC time to issue a Final Order by the end of 2004. FirstEnergy is unable to predict the outcome of the investigation or the impact of the PPUC order. 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 16 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. In July 2000, the PUCO approved FirstEnergy's transition plan for OE, CEI and TE (Ohio EUOC) 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 EUOC's 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 EUOC 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: o A competitive auction, which would establish a price for generation that customers would be charged during the period covered by the auction, or o A Rate Stabilization Plan, which would extend current generation prices through 2008, ensuring adequate generation supply at stable prices, and continuing the Ohio EUOC's support of energy efficiency and economic development efforts. Under that proposal, the Ohio EUOC requested: o 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; o Deferral of interest costs on the accumulated shopping incentives and other cost deferrals as new regulatory assets; and o 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, FirstEnergy 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 FirstEnergy's revised Rate Stabilization Plan application. Among the major modifications were the following: o Limiting the ability of the Ohio EUOC to request adjustments in generation charges during 2006 through 2008 for increases in taxes; 17 o Expanding the availability of market support generation; o Revising the kilowatt-hour target level and the time period for recovering regulatory transition charges; o Establishing a 3-year competitive bid process for generation; o Establishing the 2005 generation credit for shopping customers, which would be extended as a cap through 2008; and o Denying the ability to defer costs for future recovery of distribution reliability improvement expenditures. On June 18, 2004, the Ohio EUOC 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: o Expanding the Ohio EUOC's 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; o Approving the revised kilowatt-hour target level and time period for recovery of regulatory transition costs as presented by the Ohio EUOC in their rehearing application; o Retaining the requirement for expanded availability of market support generation, but adopting the Ohio EUOC's alternative approach that conditions expanded availability on higher pricing and eliminating the requirement to reduce the interest deferral for certain affected rate schedules; o Revising the calculation of the shopping credit cap for certain commercial and small industrial rate schedules; and o Relaxing the notice requirement for availability of enhanced shopping credits in a number of instances. On August 5, 2004, FirstEnergy accepted the Rate Stabilization Plan as modified and approved by the PUCO on August 4, 2004. FirstEnergy retains 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 EUOC 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. 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: (In millions) -------------------------------------- 2004...................... $754 2005...................... 841 2006...................... 389 2007...................... 317 2008...................... 160 2009...................... 44 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 18 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 June 30, 2004, the accumulated deferred cost balance totaled approximately $425 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 discussed above. 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, JCP&L would initiate another proceeding to request recovery of additional costs incurred to enhance system reliability. In that proceeding, the NJBPU could increase the 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 charge. The MTC allows for the recovery of $465 million in deferred energy costs over the next ten years on an interim basis, thus disallowing $153 million of the $618 million provided for in a preliminary settlement agreement between certain parties. 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 other regulatory assets. JCP&L filed a 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 costs disallowances, (2) the capital structure including the rate of return, (3) merger savings, (4) amortization of costs to achieve merger savings; and (5) decommissioning. All other issues included in JCP&L's amended motion were denied. Oral arguments were held on August 4, 2004. Management cannot predict when a decision following the oral arguments may be announced by the NJBPU. 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 higher return on equity. The filing also requests an increase to the MTC deferred balance recovery of approximately $20 million annually. 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. 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. 19 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. 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 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 20 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 During 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. The new standard, as proposed, would be effective January 1, 2005, for calendar year companies. FirstEnergy will not be able to determine the exact impact of the proposed standard on its results of operations until the standard is issued in final form. The impact of the fair value recognition provisions of SFAS 123 on FirstEnergy's net income and earnings per share for the current reporting periods is disclosed in Note 2. EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary and Its Application to Certain Investments" On March 31, 2004, the FASB ratified the consensus reached by the EITF 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 are to be applied to other-than-temporary impairment evaluations in reporting periods beginning after June 15, 2004. FirstEnergy has available-for-sale securities with unrealized losses of approximately $21 million as of June 30, 2004 and other equity investments that will be evaluated in accordance with EITF 03-1 in the third quarter of 2004. Implementation of this guidance is not expected to have a material impact on the consolidated financial statements of the Companies. EITF Issue No. 03-6, "Participating Securities and the Two-Class Method Under Financial Accounting Standards Board Statement No. 128, Earnings per Share" On March 31, 2004, the FASB ratified the consensus reached by the EITF on Issue 03-6. The issue addresses a number of questions regarding the computation of earnings per share by companies that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of a company when, and if, it declares dividends on its common stock. The issue also provides further guidance in applying the two-class method of computing earnings per share once it is determined that a security is participating, including how to allocate undistributed earnings to such a security. EITF 03-6 was effective for fiscal periods beginning after March 31, 2004 and had no impact on FirstEnergy's computation of earnings per share. 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 six months ended June 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" 21 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 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). 22 Segment Financial Information -----------------------------

Reconciling adjustments to segment operating results from internal management reporting to consolidated external financial reporting: (a) Principally fuel marketing revenues which are reflected as reductions to expenses for internal management reporting purposes. (b) Elimination of intersegment transactions. 23 FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF INCOME (Unaudited)

FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)

FIRSTENERGY CORP. CONSOLIDATED BALANCE SHEETS (Unaudited)

FIRSTENERGY CORP. CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

99 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Stockholders and Board of Directors of FirstEnergy Corp.: We have reviewed the accompanying consolidated balance sheet of FirstEnergy Corp. and its subsidiaries as of June 30, 2004, and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month and six-month periods ended June 30, 2004 and 2003. These interim financial statements are the responsibility of the Company's management. We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America. We previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet and the consolidated statement of capitalization as of December 31, 2003, and the related consolidated statements of income, common stockholders' equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company's change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 2(F) to those consolidated financial statements and the Company's change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 9 to those consolidated financial statements) dated February 25, 2004 we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2003, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived. PricewaterhouseCoopers LLP Cleveland, Ohio August 6, 2004 28 FIRSTENERGY CORP. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION EXECUTIVE SUMMARY Net income in the second quarter of 2004 was $204 million, or basic and diluted earnings of $0.62 per share of common stock, compared to a net loss of $58 million, or $0.20 per share of common stock for the second quarter of 2003. FirstEnergy's second quarter earnings reflect solid progress - particularly in the areas of sales from its regulated segment and performance of its generation portfolio. Net income in the first half of 2004 was $378 million, or $1.16 per share of common stock ($1.15 diluted), compared to $161 million, or $0.55 per share of common stock ($0.54 diluted) for the first six months of 2003. Earnings in the second quarter and first six months of 2004 were reduced on a per share basis from the issuance and sale of 32.2 million shares of common stock in the third quarter of 2003. The additional shares reduced earnings per share of common stock (basic and diluted) by $0.07 and $0.13, respectively. Higher sales in the second quarter of 2004, compared with the year-earlier quarter, were related to a stronger economy and warmer weather. Revenues were offset slightly by lower prices that resulted from a reduction in JCP&L base rates and higher customer shopping levels to alternate suppliers in FirstEnergy's Ohio service area. Sales from FirstEnergy's regulated utility companies remain the largest source of revenues, contributing more than 60% of total revenues. The restart of the Davis-Besse Nuclear Power Station, which began operating at full power on April 4, 2004, and improved performance of the generation fleet, continue to have a positive impact on earnings. Reorganization of FENOC is expected to further increase operating efficiency at FirstEnergy's three nuclear plants by standardizing structure and processes. FirstEnergy's pension and other postemployment benefits expense decreased by $22 million in the second quarter of 2004, compared to the same period last year, due to higher trust asset values, revisions to its health care benefits plan, and the positive impact of the new Medicare Act, enacted in December 2003. The same factors contributed to a $48 million decrease in the first half of 2004, compared to the first half of 2003. FirstEnergy further strengthened its financial position during the second quarter of 2004 by divesting its 50% interest in GLEP, generating after-tax net proceeds of $150 million that were used to reduce debt. This sale is consistent with FirstEnergy's strategy to divest non-core assets and focus on its core electric business. In addition to that, FirstEnergy has substantially completed divestiture of all international operations - acquired as part of its merger with the former GPU - and sold three HVAC companies in the past 18 months. FirstEnergy's debt paydown program resulted in a decrease of approximately $600 million in total debt during the first half of 2004. FirstEnergy remains on track to achieve its goal of reducing debt by at least $1 billion this year. FirstEnergy also improved its financial flexibility with the replacement of $1 billion of its credit commitments that, combined with other existing credit facilities, brings the total capacity of FirstEnergy's primary credit facilities and those of its subsidiaries to $2.3 billion. On July 23, 2004, FirstEnergy announced that Richard R. Grigg was elected Executive Vice President and Chief Operating Officer. Mr. Grigg retired earlier this year as President and Chief Executive Officer of WE Generation, after nearly 34 years with Wisconsin Energy Corporation. He will join FirstEnergy in the third quarter of 2004 and will lead several operating business units including Energy Delivery, Fossil Generation and Commodity Operations. On June 18, 2004, FirstEnergy filed a request for rehearing of portions of its Ohio Rate Stabilization Plan, which the PUCO approved with modifications on June 9, 2004. On August 5, 2004, FirstEnergy accepted the Rate Stabilization Plan as modified and approved by the PUCO on August 4, 2004. In addition to providing enhanced customer benefits, the approved plan adequately addressed most of the issues raised by FirstEnergy. These included the ability to seek recovery of increased fuel costs and terms for offering market support generation. In the second quarter of 2004, FirstEnergy implemented the accounting modifications approved by the PUCO in the Rate Stabilization Plan order. On July 27, 2004, FirstEnergy announced that it had reached an agreement to resolve various pending legal proceedings filed against FirstEnergy and certain of its officers and directors, alleging violations of federal securities laws and related state laws (see Outlook - Other Legal Matters below) in connection with financial restatements of previously reported results in August 2003, the regional power outage on August 14, 2003, and the extended outage at the Davis-Besse Nuclear Power Station. The settlement agreement, which 29 does not constitute an admission of wrongdoing, provides for a total settlement payment of $89.9 million, of which FirstEnergy's insurance carrier will pay $71.92 million. FirstEnergy will pay $17.98 million, resulting in an after-tax charge against FirstEnergy's second quarter and year-to-date 2004 earnings of $11 million or $0.03 per common share (basic and diluted). The settlement is subject to court approval and, although not anticipated to occur, in the event that a significant number of shareholders do not accept the terms of the settlement, the Company and individual defendants have the right, but not the obligation, to set aside the settlement and recommence the litigation. FirstEnergy is participating in meaningful settlement negotiations with the parties to the New Source Review case involving its W. H. Sammis Plant (see Outlook - Environmental Matters). As a result, the U.S. District Court judge hearing the case has rescheduled the date for the remedy phase of the trial to January 2005. FirstEnergy continues to make investments designed to enhance customer service reliability. Installation of new computer equipment for its system control centers in Ohio and Pennsylvania was completed in the second quarter of 2004 and control room operator training and procedures were strengthened. An enhanced vegetation management program includes foot patrols and more comprehensive aerial patrols of FirstEnergy's high-voltage transmission system. Recently, FirstEnergy received verification from the NERC of its completion of the various items related to NERC's readiness audit and reliability recommendations, as well as the U.S. - Canada Task Force findings. FirstEnergy's Business FirstEnergy Corp. is a registered public utility holding company headquartered in Akron, Ohio that provides regulated and competitive energy services (see Results of Operations - Business Segments). FirstEnergy continues to pursue its goal of being the leading supplier of energy and related services in portions of the Midwest and mid-Atlantic regions of the United States, where it sees the best opportunities for growth. FirstEnergy's fundamental business strategy remains stable and unchanged. While FirstEnergy continues to build toward a strong regional presence, key elements for its strategy are in place and management's focus continues to be on execution. FirstEnergy intends to continue providing competitively priced, high-quality products and value-added services - energy sales and services, energy delivery, power supply and supplemental services related to its core business. As the industry changes to a more competitive environment, FirstEnergy has taken and expects to take actions designed to create a larger, stronger regional enterprise that will be positioned to compete in the changing energy marketplace. FirstEnergy's eight electric utility operating companies provide transmission and distribution services and comprise the nation's fifth largest investor-owned electric system, serving 4.4 million customers within 36,100 square miles of Ohio, Pennsylvania and New Jersey. Competitive services are principally provided by FES, FSG, MYR and FirstEnergy's majority owned FirstCom. Services provided through these subsidiaries include heating, ventilation, air-conditioning, refrigeration, process piping, plumbing, electrical and facility control systems and high-efficiency electrotechnologies. Telecommunication services such as local and long-distance phone service are also provided to more than 65,000 customers. While competitive revenues have increased since 2001, regulated energy services continue to provide, in aggregate, the majority of FirstEnergy's revenues and earnings. Beginning in 2001, Ohio utilities that offered both competitive and regulated retail electric services were required to implement a corporate separation plan approved by the PUCO - one which provided a clear separation between regulated and competitive operations. FES provides competitive retail energy services while the EUOC provide regulated transmission and distribution services. FGCO, a wholly owned subsidiary of FES, leases fossil and hydroelectric plants from the EUOC and operates those plants. Under the terms of the Ohio Rate Stabilization Plan, the deadline for achieving structural separation by transferring the ownership of applicable EUOC generating assets to FGCO was extended until twelve months after the termination of the Rate Stabilization Plan, unless otherwise extended further by the PUCO, or until December 31, 2008, whichever is earlier. All of the EUOC power supply requirements for the Ohio Companies (OE, CEI and TE) and Penn are provided by FES to satisfy their PLR obligations, as well as their grandfathered wholesale contracts. FirstEnergy acquired international assets through its merger with GPU in November 2001. GPU Capital and its subsidiaries provided electric distribution services in foreign countries (see Results of Operations - Discontinued Operations). GPU Power and its subsidiaries owned and operated generation facilities in foreign countries. As of January 30, 2004, substantially all of the international operations had been divested (see Note 5) - supporting FirstEnergy's commitment to focus on its core electric business. FirstEnergy's current focus includes: (1) continuing safe operations; (2) enhancing customer service; (3) optimizing its generation portfolio; (4) minimizing unplanned extended generation outages; (5) effectively managing commodity supplies and risks; (6) reducing its cost structure; (7) enhancing its credit profile and financial flexibility; and (8) managing the skills and diversity of its workforce. 30 Reclassifications As further discussed in Notes 1 and 8 to the Consolidated Financial Statements, amounts for purchased power, other operating costs and provisions for depreciation and amortization in FirstEnergy's 2003 Consolidated Statements of Income were reclassified to conform with the current year presentation of generation commodity costs. These reclassifications did not change previously reported results in 2003. In addition, as discussed in Note 2 to the Consolidated Financial Statements, reporting of discontinued operations also resulted in the reclassification of revenues, expenses and taxes. RESULTS OF OPERATIONS The increase in net income of $262 million in the second quarter and $217 million in the first six months of 2004 includes an increase in income from continuing operations of $194 million and $253 million, respectively, when current period results are compared to those of 2003. A significant portion of the improvement between periods resulted from a charge of $159 million included in the second quarter of 2003 for costs disallowed in the JCP&L rate case decision of July 2003. The remaining difference in the second quarter earnings is attributable to an after-tax charge of $67 million or $0.23 per share of common stock (basic and diluted) in the second quarter of 2003 resulting from the abandonment of FirstEnergy's shares in Emdersa's parent company, GPU Argentina Holdings, Inc. Results in the first six months of 2003 also included an after-tax credit of $102 million resulting from the cumulative effect of an accounting change due to the adoption of SFAS 143. The results for the three and six months ended June 30, 2004 and 2003 are summarized in the table below.

Results of Operations - Second Quarter of 2004 Compared With the Second Quarter of 2003 Total revenues increased $297 million in the second quarter of 2004. The sources of changes in total revenues are summarized in the following table: 31 Three Months Ended June 30, --------------------- Increase Sources of Revenue Changes 2004 2003 (Decrease) -------------------------------------------------------------------------------- (In millions) Retail Electric Sales: EUOC - Wires..................... $1,133 $1,145 $ (12) - Generation......... 757 726 31 FES.............................. 164 122 42 Wholesale Electric Sales: EUOC............................. 127 129 (2) FES.............................. 463 251 212 ------------------------------------------------------------------------------ Total Electric Sales............... 2,644 2,373 271 ------------------------------------------------------------------------------ Transmission Revenues.............. 89 17 72 Gas Sales.......................... 114 130 (16) Other Revenues: Regulated services................ 64 65 (1) Competitive services.............. 232 233 (1) International..................... -- 7 (7) Miscellaneous..................... 7 28 (21) -------------------------------------------------------------------------------- Total Revenues..................... $3,150 $2,853 $ 297 ================================================================================ Changes in electric generation kilowatt-hour sales and distribution deliveries in the second quarter of 2004 are summarized in the following table: Increase Changes in KWH Sales (Decrease) ------------------------------------------------------ Electric Generation Sales: Retail - EUOC.................................. (0.7)% FES................................... 12.5 % Wholesale............................... 37.0 % ------------------------------------------------------ Total Electric Generation Sales.......... 12.0 % ====================================================== EUOC Distribution Deliveries: Residential............................. 6.4% Commercial.............................. 5.2% Industrial.............................. 1.2% ------------------------------------------------------ Total Distribution Deliveries............ 4.0% ====================================================== Retail sales by FirstEnergy's EUOC remain the largest source of revenues, contributing more than 70% of electric revenues and over 60% of total revenues. The following major factors contributed to the $19 million increase in retail electric revenues from FirstEnergy's EUOC in the second quarter of 2004. Sources of the Changes in EUOC Retail Electric Revenue ------------------------------------------------------ Increase (Decrease) (In millions) Changes in Customer Consumption: Alternative suppliers.................. $(22) Economic, weather and other............ 64 ---------------------------------------------------- 42 Changes in Price: Rate changes........................... (10) Shopping incentives.................... (19) Rate mix and other..................... 6 ---------------------------------------------------- (23) ---------------------------------------------------- Net Increase............................. $ 19 ==================================================== Increased customer usage offset in part by lower rates contributed to higher EUOC retail electric revenues. A stronger economy and warmer weather in the second quarter of 2004 compared to the same quarter of 2003 combined to more than offset the effect of reduced usage due to alternative energy suppliers providing a larger portion of franchise customer energy requirements. Alternative suppliers provided 25.0% of the total energy delivered to retail customers in the second quarter of 2004, compared to 21.4% in the same period of 2003. Overall, generation sales added $31 million to the increase in EUOC revenues. While distribution throughput increased in the second quarter of 2004 compared to the same period last year, distribution revenues decreased, reflecting lower rates. On July 25, 2003, the NJBPU announced its JCP&L base electric rate proceeding decision (see Outlook - State Regulatory Matters - New Jersey), which reduced JCP&L's base distribution rates effective August 1, 2003 and lowered revenues in the second quarter of 2004. Incentives to encourage customer shopping contributed another $19 million to the decrease. 32 Electric sales by FES increased by $254 million primarily from additional spot sales to the wholesale market which increased $212 million in the second quarter of 2004. Higher electric sales to the wholesale market resulted in part from nuclear generation more than doubling its output, primarily as a result of the Davis-Besse restart and fewer outages, which increased total available internal generation by 22%. Competitive retail sales increased by $42 million, primarily from customers within FirstEnergy's Ohio franchise areas switching to FES under Ohio's electricity choice program. FirstEnergy's regulated and unregulated subsidiaries record purchase and sales transactions with PJM on a gross basis in accordance with EITF 99-19. This gross basis classification of revenues and costs may not be comparable to other energy companies that operate in regions that have not established ISOs and do not meet EITF 99-19 criteria. The aggregate purchase and sales transactions for the three months ended June 30, 2004 and 2003 are summarized as follows: Three Months Ended June 30, -------------------------- 2004 2003 (1) ----------------------------------------------------------- (In millions) Sales......................... $382 $201 Purchases..................... 319 217 ------------------------------------------------------- (1) Certain prior year energy sales and purchases amounts have been reclassified to transmission revenues and expenses (see Note 8). FirstEnergy's revenues on the Consolidated Statements of Income include wholesale electricity sales revenues from PJM from power sales (as reflected in the table above) during periods when it had additional available power capacity. Revenues also include sales by FirstEnergy of power sourced from PJM (reflected as purchases in the table above) during periods when it required additional power to meet FirstEnergy's retail load requirements and, secondarily, to sell to the wholesale market. Transmission revenues increased $72 million ($16 million net of related expenses), primarily reflecting transactions with MISO, which began operations in December 2003 through the pooling of transmission capacity of Midwestern utilities to provide unbundled, regional transmission services for electric utilities. Natural gas sales were $15 million lower (excluding the GLEP partnership interest) primarily due to the expiration of FES customer choice contracts and reduced sales to the wholesale market. Lower than anticipated margins and higher administrative costs resulted in FES exiting customer choice markets as contracts expired. FES scaled back its participation in the natural gas wholesale market due to increasing volatility and risk associated with that business. Increased sales to large commercial and industrial customers in the second quarter of 2004 reflected higher prices - partially offset by declines in sales to the customer choice and wholesale markets. The generation margin in the second quarter of 2004 improved by $226 million compared to the same period in 2003. A major portion of the improvement resulted from the effect of $153 million of purchased power costs disallowed in the JCP&L rate case decision of 2003 that were expensed in the second quarter of that year. Excluding the impact of the JCP&L decision, the generation margin increased $73 million, benefiting from additional lower-cost nuclear generation. Higher electric generation sales resulted principally from the additional sales to the wholesale market. The gas margin increased $6 million despite lower overall sales volumes due to better unit margins on increased sales to commercial and industrial customers using low cost supply previously dedicated to the customer choice contracts.

(1) Excludes GLEP partnership interest. Income before income taxes, discontinued operations and cumulative effect of an accounting change increased $353 million in the second quarter of 2004. In addition to the impact of improved electric and gas margins discussed above, the following factors contributed to the increase in income before taxes: 33 o Lower nuclear production costs of $78 million primarily as a result of no nuclear refueling outages in the second quarter of 2004 compared to refueling outages at Beaver Valley Unit 1 ($15 million) and the Perry Plant ($41 million) during last year's second quarter, and reduced incremental maintenance costs at the Davis-Besse Plant ($19 million) related to its restart; o A net $25 million decrease in employee benefits expenses primarily as a result of reduced postretirement benefit plan expenses (see Postretirement Plans below); and o Lower interest expense of $26 million due to debt and preferred stock redemptions and refinancing activities and other financing activities. Discontinued Operations Net income in the second quarter of 2003 included after-tax losses from discontinued operations of $68 million reflecting the reclassification of revenues and expenses associated with divestitures of FirstEnergy's Argentina and Bolivia businesses, FSG subsidiaries (Colonial Mechanical, Webb Technologies and Ancoma, Inc.) and NEO. Postretirement Plans Strengthened equity markets, amendments to FirstEnergy's health care benefits plan in the first quarter of 2004 and the Medicare Act signed by President Bush in December 2003 combined to reduce pension and other postemployment benefits costs. Combined, these employee benefit expenses decreased by $22 million in the second quarter of 2004. The following table summarizes the net pension and OPEB expense for the three months ended June 30, 2004 and 2003. Three Months Ended Postretirement Benefits Expense(1) June 30, ------------------------------------------------------ 2004 2003 ---- ---- (In millions) Pension...................... $22 $27 OPEB......................... 21 38 ----------------------------------------------------- Total...................... $43 $65 ===================================================== (1) Excludes the capitalized portion of postretirement benefits costs (see Note 4 for total costs). The decrease in pension and OPEB expenses are included in various cost categories and have contributed to other cost reductions discussed above. See "Critical Accounting Policies - Pension and Other Postretirement Benefits Accounting" for a discussion of the impact of underlying assumptions on postretirement benefits expenses. Results of Operations - First Six Months of 2004 Compared With the First Six Months of 2003 Total revenues increased $258 million in the first six months of 2004. The sources of changes in total revenues are summarized in the following table: Six Months Ended June 30, --------------------- Increase Sources of Revenue Changes 2004 2003 (Decrease) -------------------------------------------------------------------------------- (In millions) Retail Electric Sales: EUOC - Wires..................... $2,296 $2,359 $ (63) - Generation 1,512 1,511 1 FES.............................. 335 242 93 Wholesale Electric Sales: EUOC............................. 250 342 (92) FES.............................. 907 543 364 ---------------------------------------------------------------------------- Total Electric Sales............... 5,300 4,997 303 ---------------------------------------------------------------------------- Transmission Revenues.............. 167 30 137 Gas Sales.......................... 278 374 (96) Other Revenues: Regulated services............... 122 157 (35) Competitive services............. 452 435 17 International.................... -- 15 (15) Miscellaneous.................... 13 66 (53) ------------------------------------------------------------------------------- Total Revenues..................... $6,332 $6,074 $258 =============================================================================== 34 Changes in electric generation kilowatt-hour sales and distribution deliveries in the first six months of 2004 are summarized in the following table: Increase Changes in KWH Sales (Decrease) ------------------------------------------------------ Electric Generation Sales: Retail - EUOC................................ (3.7)% FES................................. 18.3 % Wholesale.............................. 28.0 % ------------------------------------------------------ Total Electric Generation Sales.......... 7.8 % ====================================================== EUOC Distribution Deliveries: Residential............................ 2.6% Commercial............................. 2.6% Industrial............................. 1.0% ------------------------------------------------------ Total Distribution Deliveries............ 2.0% ====================================================== Retail sales by FirstEnergy's EUOC remain the largest source of revenues, contributing more than 70% of electric revenues and over 60% of total revenues. The following major factors contributed to the $62 million reduction in retail electric revenues from FirstEnergy's EUOC in the first six months of 2004. Sources of the Changes in EUOC Retail Electric Revenue ------------------------------------------------------ Increase (Decrease) (In millions) Changes in Customer Consumption: Alternative suppliers.................. $(78) Economic, weather and other............ 67 ---------------------------------------------------- (11) ---------------------------------------------------- Changes in Price: Rate changes........................... (42) Shopping incentives.................... (26) Rate mix and other..................... 17 ---------------------------------------------------- (51) ---------------------------------------------------- Net Decrease............................. $(62) ==================================================== Reductions in both customer usage and prices contributed to lower EUOC retail electric revenues. Customers shopping in FirstEnergy's franchise areas for alternative energy suppliers remained the largest single factor for the reduced usage. Alternative suppliers provided 24.5% of the total energy delivered to retail customers in the first six months of 2004, compared to 20.1% in the same period of 2003. A stronger economy and warmer weather in the second quarter of 2004 compared to the same quarter of 2003 combined to substantially offset the effect of reduced usage due to alternative energy suppliers providing a larger portion of franchise customer energy requirements. While distribution throughput increased 2%, distribution revenues decreased - reflecting lower rates. On July 25, 2003, the NJBPU announced its JCP&L base electric rate proceeding decision (see Regulatory Matters - New Jersey), which reduced JCP&L's base distribution rates effective August 1, 2003. The lower rates reduced revenues by $42 million in the first six months of 2004. EUOC sales to wholesale customers decreased by $92 million on a 31% reduction in kilowatt-hour sales - JCP&L's sales represented substantially all of the decrease. Electric sales by FES increased by $457 million primarily from additional spot sales to the wholesale market which increased $364 million for the first six months of 2004. Higher electric sales to the wholesale market resulted from a 16% increase in internal generation available from FirstEnergy's nuclear (50% increase) and fossil (2% increase) generating plants. Retail sales increased by $93 million, primarily from customers within FirstEnergy's Ohio franchise areas switching to FES under Ohio's electricity choice program. FirstEnergy's regulated and unregulated subsidiaries record purchase and sales transactions with PJM on a gross basis in accordance with EITF 99-19. This gross basis classification of revenues and costs may not be comparable to other energy companies that operate in regions that have not established ISOs and do not meet EITF 99-19 criteria. The aggregate purchase and sales transactions for the six months ended June 30, 2004 and 2003 are summarized as follows: 35 Six Months Ended June 30, -------------------------- 2004 2003 (1) ----------------------------------------------------------- (In millions) Sales......................... $748 $445 Purchases..................... 649 564 ------------------------------------------------------ (1) Certain prior year energy sales and purchases amounts have been reclassified to transmission revenues and expenses (see Note 8). FirstEnergy's revenues on the Consolidated Statements of Income include wholesale electricity sales revenues from PJM from power sales (as reflected in the table above) during periods when it had additional available power capacity. Revenues also include sales by FirstEnergy of power sourced from PJM (reflected as purchases in the table above) during periods when it required additional power to meet FirstEnergy's retail load requirements and, secondarily, to sell to the wholesale market. Transmission revenues increased $137 million ($37 million net of related expenses), primarily reflecting transactions with MISO, which began operations in December 2003 through the pooling of transmission capacity of Midwestern utilities to provide unbundled regional transmission services for electric utilities. Natural gas sales decreased $96 million primarily due to the expiration of FES customer choice contracts and reduced sales to the wholesale market. Lower than anticipated margins and higher administrative costs resulted in FES exiting customer choice markets as contracts expired. FES scaled back its participation in the natural gas wholesale market due to increasing volatility and risk associated with that business. Lower sales to large commercial and industrial customers in the first half of 2004, compared to the same period in 2003 primarily reflected fewer customers. The generation margin in the first six months of 2004 improved by $276 million compared to the same period in 2003 as electric generation revenues increased faster than the related costs for fuel and purchased power. Excluding the impact of the July 2003 JCP&L rate decision discussed above, generation margin increased $123 million and the ratio of generation margin to revenue improved from 24.7% to 25.8% benefiting from additional lower-cost nuclear generation. Higher electric generation sales resulted principally from the additional sales to the wholesale market. The gas margin decreased $3 million on reduced sales.

(1) Excludes GLEP partnership interest. Income before income taxes, discontinued operations and cumulative effect of an accounting change increased $434 million in the first six months of 2004. In addition to the impact of improved electric and gas margins discussed above, the following factors contributed to the increase in income before taxes: o Lower nuclear production costs of $150 million primarily as a result of no nuclear refueling outages in the first six months of 2004 compared to refueling outages at Beaver Valley Unit 1 ($47 million) and the Perry Plant ($41 million) during the same period last year and reduced incremental maintenance costs at the Davis-Besse Plant ($54 million) related to its restart; o A net $44 million decrease in employee benefits expenses primarily as a result of reduced postretirement benefit plan expenses (see Postretirement Plans below); and o Lower interest expense of $60 million due to debt and preferred stock redemptions and refinancing activities. 36 Partially offsetting the above sources of improved earnings were two factors: o Reduced revenues of $63 million from distribution deliveries (primarily due to reduced rates); and o Charges for depreciation and amortization that increased by $31 million due to an increase in amortization of regulatory assets offset in part by reduced depreciation rates resulting from the JCP&L rate case. The increase in regulatory asset amortization was primarily due to increased amortization of the Ohio transition plan regulatory assets net of deferrals and increased stranded cost amortization at JCP&L, Met-Ed and Penelec. Discontinued Operations Net income in the first six months of 2003 included after-tax losses from discontinued operations of $66 million reflecting the reclassification of revenues and expenses associated with divestitures of FirstEnergy's Argentina and Bolivia businesses, FSG subsidiaries (Colonial Mechanical, Webb Technologies and Ancoma, Inc) and NEO. Cumulative Effect of Accounting Change Results in the first six months of 2003 included an after-tax credit to net income of $102 million recorded upon the adoption of SFAS 143 in January 2003. FirstEnergy identified applicable legal obligations as defined under the new standard for nuclear power plant decommissioning and reclamation of a sludge disposal pond at the Bruce Mansfield Plant. As a result of adopting SFAS 143 in January 2003, asset retirement costs of $602 million were recorded as part of the carrying amount of the related long-lived asset, offset by accumulated depreciation of $415 million. The ARO liability at the date of adoption was $1.11 billion, including accumulated accretion for the period from the date the liability was incurred to the date of adoption. As of December 31, 2002, FirstEnergy had recorded decommissioning liabilities of $1.24 billion. FirstEnergy expects substantially all of its nuclear decommissioning costs for Met-Ed, Penelec, JCP&L and Penn to be recoverable in rates over time. Therefore, FirstEnergy recognized a regulatory liability of $185 million upon adoption of SFAS 143 for the transition amounts related to establishing the ARO for nuclear decommissioning for those companies. The remaining cumulative effect adjustment for unrecognized depreciation and accretion offset by the reduction in the liabilities and the reversal of accumulated estimated removal costs for non-regulated generation assets, was a $175 million increase to income, or $102 million net of income taxes. Postretirement Plans Strengthened equity markets in 2003, amendments to FirstEnergy's health care benefits plan in the first quarter of 2004 and the Medicare Act signed by President Bush in December 2003 combined to reduce pension and other postemployment benefits costs. Combined, these employee benefit expenses decreased by $48 million in the first six months of 2004. The following table summarizes the net pension and OPEB expense for the six months ended June 30, 2004 and 2003. Six Months Ended Postretirement Benefits Expense(1) June 30, ------------------------------------------------------ 2004 2003 ---- ---- (In millions) Pension...................... $43 $ 59 OPEB......................... 47 79 ------------------------------------------------------ Total...................... $90 $138 ====================================================== (1) Excludes the capitalized portion of postretirement benefits costs (see Note 4 for total costs). The decrease in pension and OPEB expenses are included in various cost categories and have contributed to other cost reductions discussed above. See "Critical Accounting Policies - Pension and Other Postretirement Benefits Accounting" for a discussion of the impact of underlying assumptions on postretirement benefits expenses. RESULTS OF OPERATIONS - BUSINESS SEGMENTS FirstEnergy manages its business as two separate major business segments - regulated services and competitive services. In the first quarter of 2004, management made certain changes in presenting results for these two segments (see Note 8). The regulated services segment no longer includes a portion of generation services. 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 cost recovery. All generation services are now reported in the competitive services segment. That segment's revenues include all generation electric sales revenues (including the generation services to regulated franchise customers who have not chosen an alternative generation 37 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, commodity sourcing and other competitive energy-application services such as heating, ventilation and air-conditioning. "Other" consists of interest expense related to holding company debt, corporate support services and the international businesses that were substantially divested by the first quarter of 2004. FirstEnergy's two major business segments include all or a portion of the following business entities: o The regulated services segment includes the regulated delivery of electricity including transmission and distribution services by its eight electric utility operating companies in Ohio, Pennsylvania and New Jersey (OE, CEI, TE, Penn, JCP&L, Met-Ed, Penelec and ATSI) o 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 as a result of the deregulation of the Companies' electric generation business (see Note 6 - Regulatory Matters). Financial results discussed below include revenues and expenses from transactions among FirstEnergy's business segments. A reconciliation of segment financial results to consolidated financial results is provided in Note 8 to the consolidated financial statements. Net income (loss) by business segment was as follows: Three Months Ended Six Months Ended Net Income (Loss) June 30, June 30, ------------------------------------------------- By Business Segment 2004 2003 2004 2003 -------------------------------------------------------------------------------- (In millions) Regulated services......... $240 $ 215 $ 456 $ 573 Competitive services....... 41 (152) 41 (247) Other(1)................... (77) (121) (119) (165) -------------------------------------------------------------------------------- Total...................... $204 $ (58) $ 378 $ 161 ================================================================================ (1) Includes international operations and reflects an after-tax charge of $67 million in the second quarter of 2003 related to the abandonment of FirstEnergy's Argentina business operations. Regulated Services - Second Quarter of 2004 Compared with the Second Quarter of 2003 Financial results for the regulated services segment were as follows: Three Months Ended June 30, ------------------ Increase Regulated Services 2004 2003 (Decrease) ------------------------------------------------------------------------------ (In millions) Total revenues............................... $1,289 $1,237 $52 Income before cumulative effect of accounting changes.................................... 240 215 25 Net Income.................................... 240 215 25 ------------------------------------------------------------------------------ The change in operating revenues resulted from the following sources: Three Months Ended June 30, --------------------- Increase Sources of Revenue Changes 2004 2003 (Decrease) --------------------------------------------------------------------- (In millions) Electric sales............. $1,133 $1,145 $(12) Other sales................ 156 92 64 ------------------------------------------------------------------- Total Sales................ $1,289 $1,237 $ 52 =================================================================== The increase in operating revenues resulted from: o A net decrease of $12 million in retail sales - a $2 million reduction in revenues from distribution deliveries (wires and transition revenue) and a $10 million increase in the credits for shopping incentives to customers; and o A net $64 million increase in other sales due to higher transmission revenues. Increased transmission revenues contributed $16 million net of expenses to the $25 million increase in income before cumulative effect of an accounting change. 38 Competitive Services - Second Quarter of 2004 Compared with the Second Quarter of 2003 Financial results for the competitive services segment were as follows: Three Months Ended June 30, --------------- Increase Competitive Services 2004 2003 (Decrease) -------------------------------------------------------------------------------- (In millions) Total revenues................................... $1,853 $1,575 $278 Income (Loss) before discontinued operations and cumulative effect of accounting changes....... 41 (152) 193 Net income (loss)................................ 41 (152) 193 -------------------------------------------------------------------------------- The change in total revenues resulted from the following sources: Three Months Ended June 30, ------------------- Increase Sources of Revenue Changes 2004 2003 (Decrease) ----------------------------------------------------------------------- (In millions) Electric sales................. $1,512 $1,229 $283 Natural gas sales.............. 114 130 (16) Energy-related sales........... 176 200 (24) Other.......................... 51 16 35 --------------------------------------------------------------------- Total Revenues................. $1,853 $1,575 $278 ===================================================================== The increase in electric revenues resulted from: o Higher retail generation sales through customer choice programs ($42 million) and increased generation sales to the EUOC ($31 million); and o Increased FES wholesale revenues of $212 million (primarily into the spot market) offset in part by a $2 million decrease in EUOC sales to wholesale customers. Natural gas sales were $16 million lower primarily due to the expiration of FES customer choice contracts and reduced sales to the wholesale market. Lower than anticipated margins and higher administrative costs resulted in FES exiting customer choice markets as contracts expired. FES scaled back its participation in the wholesale market due to increasing volatility and risk associated with that business. Increased sales to large commercial and industrial customers in the second quarter of 2004 - partially offset declines in sales to the customer choice and wholesale markets. Increased sales revenues also reflected higher prices. The generation margin increased $226 million as the electric generation revenues increase exceeded the increase in related costs for fuel and purchased power. Higher electric generation revenues resulted from additional sales to the wholesale market which benefited from increased nuclear generation. A major portion of the improvement resulted from the effect of $153 million of purchased power costs disallowed in the JCP&L rate case decision of July 2003 that were expensed in the second quarter of that year. Excluding the impact of the JCP&L decision, the generation margin increased $73 million benefiting from additional lower-cost nuclear generation. The margin on gas sales increased $6 million despite lower overall sales volumes due to better unit margins on increased sales to commercial and industrial customers using low cost supply previously dedicated to the customer choice contracts. Income before discontinued operations and cumulative effect of accounting change increased $193 million in the second quarter of 2004 and pre-tax income increased by $327 million. In addition to the effect of improved electric and gas margins discussed above, the following factors contributed to the increase in pre-tax income: o Lower nuclear production costs of $78 million primarily as a result of no nuclear refueling outages in the second quarter of 2004 compared to refueling outages at Beaver Valley Unit 1 ($15 million) and the Perry Plant ($41 million) during last year's second quarter, and reduced incremental maintenance costs at the Davis-Besse Plant ($19 million) related to its restart; and o Reduced employee benefits expenses primarily as a result of lower postretirement benefit plan expenses (see Postretirement Plans above). 39 Regulated Services - First Six Months of 2004 Compared with the First Six Months of 2003 Financial results for the regulated services segment were as follows: Six Months Ended June 30, ---------------- Increase Regulated Services 2004 2003 (Decrease) -------------------------------------------------------------------------------- (In millions) Total revenues............................... $2,585 $2,546 $ 39 Income before cumulative effect of accounting change..................................... 456 472 (16) Net Income.................................... 456 573 (117) -------------------------------------------------------------------------------- The change in operating revenues resulted from the following sources: Six Months Ended June 30, --------------------- Increase Sources of Revenue Changes 2004 2003 (Decrease) ----------------------------------------------------------------------- (In millions) Electric sales............. $2,296 $2,359 $ (63) Other revenues............. 289 187 102 ------------------------------------------------------------------- Total Revenues............. $2,585 $2,546 $ 39 =================================================================== The increase in operating revenues resulted from: o A net decrease of $63 million in retail sales - a $57 million decrease in revenues from distribution deliveries and a $6 million increase in shopping incentive credits to customers; and o A net $102 million increase in other revenues primarily due to higher transmission revenues. Increased expenses resulted in a $16 million decrease in income before cumulative effect of an accounting change. Higher expenses included a $96 million increase in operating expenses from additional transmission expenses, energy delivery costs for vegetation management and JCP&L's accelerated reliability program, as well as increased depreciation and amortization charges of $26 million. Competitive Services - First Six Months of 2004 Compared with the First Six Months of 2003 Financial results for the competitive services segment were as follows: Six Months Ended June 30, --------------- Increase Competitive Services 2004 2003 (Decrease) ------------------------------------------------------------------------------ (In millions) Total revenues................................... $3,726 $3,449 $277 Income (Loss) before discontinued operations and cumulative effect of accounting changes....... 41 (243) 284 Net income (loss)................................ 41 (247) 288 ------------------------------------------------------------------------------ The change in total revenues resulted from the following sources: Six Months Ended June 30 ------------------- Increase Sources of Revenue Changes 2004 2003 (Decrease) ----------------------------------------------------------------------- (In millions) Electric sales................. $3,005 $2,639 $366 Natural gas sales.............. 278 374 (96) Energy-related sales........... 354 387 (33) Other.......................... 89 49 40 --------------------------------------------------------------------- Total Revenues................. $3,726 $3,449 $277 ===================================================================== The increase in electric revenues resulted from: o Higher retail generation sales from customer choice programs ($93 million) and an increase in generation sales to the EUOC ($1 million); and 40 o Increased wholesale revenues of $364 million from FES (primarily into the spot market) offset in part by a $92 million decrease in EUOC sales to wholesale customers. Natural gas sales decreased $96 million primarily due to the expiration of FES customer choice contracts and reduced sales to the wholesale market. Lower than anticipated margins and higher administrative costs resulted in FES exiting customer choice markets as contracts expired. Due to increased volatility and perceived risk, FES reduced its participation in the wholesale market. Decreased sales to large commercial and industrial customers in the first half of 2004 primarily reflected fewer customers. The generation margin increased $276 million as electric generation revenues increased faster than the related costs for fuel and purchased power. Higher electric generation revenues resulted from additional sales to the wholesale market. Excluding the impact of the July 2003 JCP&L rate decision, as discussed above, the generation margin increased $123 million. The margin on gas sales decreased $3 million on reduced sales. Income before discontinued operations and cumulative effect of an accounting change increased $284 million in the first six months of 2004. In addition to the effect of improved generation and gas margins discussed above, the following factors contributed to that increase: o Lower nuclear production costs of $150 million primarily as a result of no nuclear refueling outages in the first six months of 2004 compared to refueling outages at Beaver Valley Unit 1 ($47 million) and the Perry Plant ($41 million) during the same period last year and reduced incremental maintenance costs at the Davis-Besse Plant ($54 million) related to its restart; and o Reduced employee benefits expenses primarily as a result of lower postretirement benefit plan expenses (see Postretirement Plans above). CAPITAL RESOURCES AND LIQUIDITY FirstEnergy's cash requirements in 2004 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing FirstEnergy's net debt and preferred stock outstanding. Available borrowing capacity under short-term credit facilities will be used to manage working capital requirements. Over the next two years, FirstEnergy expects to meet its contractual obligations with cash from operations. Thereafter, FirstEnergy expects to use a combination of cash from operations and funds from the capital markets. Changes in Cash Position The primary source of ongoing cash for FirstEnergy, as a holding company, is cash dividends from its subsidiaries. The holding company also has access to $1.375 billion of revolving credit facilities. In the first six months of 2004, FirstEnergy received $391 million of cash dividends from its subsidiaries and paid $244 million in cash common stock dividends to its shareholders. There are no material restrictions on the issuance of cash dividends by FirstEnergy's subsidiaries. As of June 30, 2004, FirstEnergy had $100 million of cash and cash equivalents, compared with $114 million as of December 31, 2003. The major sources for changes in these balances are summarized below. Cash Flows From Operating Activities FirstEnergy's consolidated net cash from operating activities is provided by its regulated and competitive energy services businesses (see Results of Operations - Business Segments above). Net cash provided from operating activities in the second quarter and first six months of 2004, compared with the corresponding periods of 2003 were as follows: Three Months Ended Six Months Ended June 30, June 30, ------------------- ------------------ Operating Cash Flows 2004 2003 2004 2003 ------------------------------------------------------------------------------ (In millions) Cash earnings (1) $380 $ 381 $889 $ 744 Working capital and other (60) (359) 81 (260) ------------------------------------------------------------------------------ Total $320 $ 22 $970 $ 484 ============================================================================== (1) Includes net income, depreciation and amortization, deferred income taxes, investment tax credits and major noncash charges. 41 Net cash provided from operating activities increased $298 million in the second quarter of 2004 compared to the same period last year due to changes in working capital. The working capital change resulted primarily from increases in accounts payable and accrued taxes. During the first six months of 2004, net cash provided from operating activities increased $486 million due to a $341 million increase from changes in working capital and $145 million of higher cash earnings, reflecting improving generation margins. The working capital change primarily resulted from a $232 million increase in receivables (including the net proceeds from the settlement of FirstEnergy's claim against NRG, Inc. for the terminated sale of four power plants) and a $125 million increase in accrued taxes, partially offset by a $74 million decrease in accounts payable. Cash Flows From Financing Activities The following table provides details regarding security issuances and redemptions during the second quarter and first six months of 2004 and 2003: Three Months Ended Six Months Ended June 30, June 30, ------------------ ---------------- Securities Issued or Redeemed 2004 2003 2004 2003 ----------------------------------------------------------------------------- (In millions) New Issues Pollution control notes........ $ -- $ -- $ 185 $ -- Senior secured notes........... 300 159 550 409 Unsecured notes................ 3 333 150 331 Long-term revolving credit..... -- 230 -- 280 ----------------------------------------------------------------------------- $303 $722 $ 885 $1,020 Redemptions First mortgage bonds........... $290 $593 $ 382 $ 633 Pollution control notes........ -- -- -- 50 Senior secured notes........... 31 222 73 333 Long-term revolving credit..... 175 -- 310 -- Unsecured notes................ 225 -- 225 -- Preferred stock................ -- 125 -- 125 ----------------------------------------------------------------------------- $721 $940 $ 990 $1,141 ----------------------------------------------------------------------------- Short-term Borrowings, Net ........ $(59) $190 $(447) $ (48) ----------------------------------------------------------------------------- Net cash used for the above financing activities increased by $454 million in the second quarter of 2004 from the second quarter of 2003. The increase in funds used for financing activities resulted from an increase in net redemptions and refinancings of debt and preferred securities of $449 million. Redemption and refinancing activities for debt and preferred stock aggregated approximately $677 million during the second quarter of 2004 (including $189 million of pollution control note repricings). The redemption and refinancing activities and pollution control note repricings are expected to result in annualized savings of $35 million. Net cash used for the above financing activities increased by $457 million in the first six months of 2004 from the same period of 2003. The increase in funds used for financing activities resulted primarily from an increase in net redemptions of debt and preferred securities of $383 million and higher dividend payments in 2004. FirstEnergy has requirements of approximately $598 million to meet sinking fund requirements for preferred stock and maturing long-term debt during the remainder of 2004. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. FirstEnergy had approximately $74 million of short-term indebtedness as of June 30, 2004 compared to approximately $522 million as of December 31, 2003. Unused borrowing capability as of June 30, 2004 included the following: 42 FirstEnergy Unused Borrowing Capability Holding Company OE Total -------------------------------------------------------------------------------- (In millions) Long-Term Revolving Credit................... $1,375 $375 $1,750 Utilized..................................... -- -- -- Letters of Credit............................ (152) -- (152) -------------------------------------------------------------------------------- Net.......................................... 1,223 375 1,598 ------------------------------------------------------------------------------- Short-Term Bank Facilities................... -- 34 34 Utilized..................................... -- -- -- ------------------------------------------------------------------------------- Net.......................................... -- 34 34 ------------------------------------------------------------------------------- Total Unused Borrowing Capability............ $1,223 $409 $1,632 =============================================================================== On June 7, 2004, OE replaced certain collateralized letters of credit that were issued in 1994 in support of OE's obligations to lessors under the Beaver Valley Unit 2 sale and leaseback arrangements. Approximately $289 million in cash collateral and accrued interest previously held by OES Finance Incorporated, a wholly owned subsidiary of OE, was released on July 15, 2004, upon cancellation of the existing letters of credit and was used to repay short-term debt and for other corporate purposes. Simultaneously with the issuance of the replacement letters of credit, OE entered into a Credit Agreement pursuant to which a standby letter of credit was issued in support of the replacement letters of credit, and the issuer of the letters of credit obtained the right to pledge or assign participations in OE's reimbursement obligations to a trust. The trust then issued and sold trust certificates to institutional investors that were designed to be the credit equivalent of an investment directly in OE. As of June 30, 2004, the Ohio EUOC and Penn had the aggregate capability to issue approximately $3.1 billion of additional FMB on the basis of property additions and retired bonds, although unsecured senior note indentures entered into by OE and CEI in 2004 limit each company's ability to issue secured debt, including FMBs, subject to certain exceptions. JCP&L and Penelec no longer issue FMB other than as collateral for senior notes, since their senior note indentures prohibit them (subject to certain exceptions) from issuing any debt which is senior to the senior notes. As of June 30, 2004, JCP&L and Penelec had the aggregate capability to issue $1.2 billion of additional senior notes using FMB collateral. Met-Ed is not limited as to the amount of senior notes it may issue. Based upon applicable earnings coverage tests in their respective charters, OE, Penn, and JCP&L could issue a total of $3.6 billion of preferred stock (assuming no additional debt was issued) as of June 30, 2004. Under its applicable earnings coverage test, TE could not issue additional preferred stock. CEI, Met-Ed and Penelec have no restrictions on the issuance of preferred stock. FirstEnergy restructured its $500 million three-year and $375 million 364-day revolving credit facilities, as well as Ohio Edison's $125 million 364-day revolving credit facility, through a syndicated bank offering that was completed on June 22, 2004. The new syndicated FirstEnergy facility consists of a single $1 billion three-year revolving credit facility. Combined with an existing syndicated $375 million three-year facility for FirstEnergy maturing in October 2006, a $125 million three-year facility for OE maturing in October 2006, and an existing syndicated $250 million two-year facility for OE maturing in May 2005, FirstEnergy's primary syndicated credit facilities total $1.75 billion. These facilities, combined with an aggregate $550 million of accounts receivable financing facilities for OE, CEI, TE, Met-Ed, Penelec and Penn, are intended to provide liquidity to meet the short-term working capital requirements of FirstEnergy and its subsidiaries. Total unused borrowing capability under existing facilities and accounts receivable financing facilities totaled $2.0 billion as of June 30, 2004. Borrowings under these facilities are conditioned on FirstEnergy and/or OE maintaining compliance with certain financial covenants in the agreements. FirstEnergy and OE are each required to maintain a debt to total capitalization ratio of no more than 0.65 to 1 and a contractually-defined fixed charge coverage ratio of no less than 2 to 1. FirstEnergy and OE are in compliance with these financial covenants. As of June 30, 2004, FirstEnergy's and OE's fixed charge coverage ratios, as defined under the credit agreements, were 3.73 to 1 and 6.84 to 1, respectively. FirstEnergy's and OE's debt to total capitalization ratios, as defined under the credit agreements, were 0.57 to 1 and 0.38 to 1, respectively. The ability to draw on each of these facilities is also conditioned upon FirstEnergy or OE making certain representations and warranties to the lending banks prior to drawing on their respective facilities, including a representation that there has been no material adverse change in their business, their condition (financial or otherwise), their results of operations, or their prospects. FirstEnergy's and OE's primary credit facilities contain no provisions restricting their ability to borrow, or accelerating repayment of outstanding loans, as a result of any change in their S&P or Moody's credit ratings. The primary facilities do contain "pricing grids", whereby the cost of funds borrowed under the facilities is related to the credit ratings of the company borrowing the funds. FirstEnergy's regulated companies have the ability to borrow from each other and the holding company to meet their short-term working capital requirements. A similar but separate arrangement exists among its competitive 43 companies. FESC administers these two money pools and tracks surplus funds of FirstEnergy and the respective regulated and competitive subsidiaries, as well as proceeds available from bank borrowings. For the regulated companies, available bank borrowings include $1.75 billion from FirstEnergy's and OE's revolving credit facilities. For the competitive companies, available bank borrowings include only the $1.375 billion of FirstEnergy's revolving credit facilities. Companies receiving a loan under the money pool agreements must repay the principal amount of such loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the second quarter of 2004 was 1.39% for the regulated companies' pool and 1.54% for the competitive companies' pool. In April and May of 2004, FirstEnergy executed seven fixed-to-floating interest rate swap agreements with notional amounts of $50 million each on underlying EUOC senior notes and subordinated debentures with an average fixed rate of 5.89%. On April 23, 2004, JCP&L issued $300 million of 5.625% Senior Notes due 2016. The proceeds of this transaction were used to redeem $40 million of 7.98% JCP&L Series C MTNs due 2023, $40 million of 8.32% JCP&L Series C MTNs due 2022, $50 million of 6.78% JCP&L Series C MTNs due 2005, $160 million of 7.125% JCP&L FMB due October 1, 2004 and to reduce short term debt. On June 1, 2004, Met-Ed used a portion of the proceeds from its March 25, 2004 $250 million 4.875% Senior Notes offering to redeem at par $100 million principal amount of its subordinated debentures in connection with the concurrent off-balance sheet redemption at par of $100 million principal amount of Met-Ed Capital Trusts 7.35% Trust Preferred Securities. On July 30, 2004, Penelec announced it would optionally redeem at par $100 million principal amount of its subordinated debentures in connection with the concurrent off-balance sheet redemption at par of $100 million principal amount of Penelec Capital Trust 7.34% Trust Preferred Securities on September 1, 2004. On April 28, 2004, Moody's published a Liquidity Risk Assessment of FirstEnergy Corp. stating that FirstEnergy had "adequate liquidity." Moody's noted that FirstEnergy's committed credit facilities at the holding company level provided a substantial source of liquidity. Moody's also noted that, in the past year, FirstEnergy had lengthened the average maturity of its bank facilities and had made reductions to its total consolidated debt level. On April 30, 2004, Moody's published a Credit Opinion of FirstEnergy Corp. Moody's cited the stable and predictable cash flows of FirstEnergy's core utility operations, management's focus on increasing financial flexibility through debt reduction and divestiture of non-core assets, FirstEnergy's integrated regional strategy, and strong liquidity as credit strengths. Moody's noted the substantial debt burden associated with the GPU merger, fully competitive generating markets, and modest growth in markets served as credit challenges for FirstEnergy. Moody's also noted that a "track record of improving financial condition, especially a track record of debt reduction, could cause the ratings to go up" and that the opposite development could cause the ratings to go down. On June 14, 2004, S&P stated that the June 9, 2004 PUCO decision on FirstEnergy's Rate Stabilization Plan did not affect the ratings or the outlook on the Company. On July 22, 2004, S&P updated its analysis of U.S. utility FMB in response to changes in the industry. As a result of its revised methodology for evaluating default risk, S&P raised its FMB credit ratings for 20 U.S. utility companies including JCP&L and Penn. JCP&L's FMB credit rating was upgraded to BBB+ from BBB and Penn's FMB credit rating was upgraded to BBB from BBB-. Cash Flows From Investing Activities Net cash flows provided from investing activities totaled $72 million in the second quarter of 2004, compared to net cash flows used of $109 million for investing activities for the same period of 2003. The $181 million change primarily resulted from $200 million in cash proceeds from the sale in the second quarter of 2004 of FirstEnergy's interest in GLEP. The following table summarizes investments by FirstEnergy's regulated services and competitive services segments in the second quarter and first six months of 2004: 44 Summary of Cash Used Property for Investing Activities Additions Investments Other Total ------------------------------------------------------------------------------ Sources (Uses) (In millions) Three Months Ended June 30, 2004 Regulated Services.................. $(129) $ 14 $ (5) $(120) Competitive Services................ (60) 178 (1) 2 120 Other............................... (7) 80 (1) 72 ------------------------------------------------------------------------------ Total.......................... $(196) $272 $ (4) $ 72 ============================================================================== Six Months Ended June 30, 2004 Regulated Services.................... $(220) $(65)(2) $ (7) $(292) Competitive Services.................. (105) 198 (1) 4 97 Other................................. (10) 53 (19) 24 ------------------------------------------------------------------------------- Total............................ $(335) $186 $(22) $(171) =============================================================================== (1) Includes $200 million in cash proceeds from the sale of GLEP. (2) Includes a $51 million refunding payment to a NUG trust fund. During the remaining two quarters of 2004, capital requirements for property additions and capital leases are expected to be approximately $453 million, including $82 million for nuclear fuel. FirstEnergy's current forecast reflects expenditures of approximately $2.3 billion for property additions and improvements from 2004-2006, of which approximately $708 million is applicable to 2004. Investments for additional nuclear fuel during the 2004-2006 period are estimated to be approximately $300 million, of which approximately $82 million applies to 2004. During the same periods, the Companies' nuclear fuel investments are expected to be reduced by approximately $274 million and $89 million, respectively, as the nuclear fuel is consumed. 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. Such agreements include contract guarantees, surety bonds, and ratings contingent collateralization provisions. As of June 30, 2004, the maximum potential future payments under outstanding guarantees and other assurances totaled approximately $2.1 billion as summarized below: Maximum Guarantees and Other Assurances Exposure ------------------------------------------------------------ (In millions) FirstEnergy Guarantees of Subsidiaries: Energy and Energy-Related Contracts (1)..... $ 850 Other (2)................................... 149 -------------------------------------------------------- 999 Surety Bonds.................................. 257 Letters of Credit (3)(4)...................... 816 -------------------------------------------------------- Total Guarantees and Other Assurances....... $2,072 ======================================================== (1) Issued for a one-year term, with a 10-day termination right by FirstEnergy. (2) Issued for various terms. (3) Includes letters of credit of $152 million issued for various terms under letter of credit capacity available in FirstEnergy's syndicated revolving credit facilities. (4) Includes unsecured letters of credit of approximately $216 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by CEI and TE, as well as an unsecured letter of credit of $237 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by OE and unsecured letters of credit of $211 million pledged in connection with the sale and leaseback of Perry Unit 1 by OE. 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 45 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 financings 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 FirstEnergy's other assets. The likelihood that such parental guarantees will increase amounts otherwise paid by FirstEnergy to meet its obligations incurred in connection with ongoing energy-related activities is remote. While these types of 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 June 30, 2004: Total Collateral Paid -------------------------- Remaining Collateral Provisions Exposure (1) Cash Letters of Credit Exposure (In millions) Rating downgrade......... $270 $161 $18 $ 91 Adverse event............ 180 -- 23 157 ----------------------------------------------------------------------------- Total.................... $450 $161 $41 $248 ============================================================================= (1) As of July 12, 2004, FirstEnergy's total exposure decreased to $437 million and the remaining exposure decreased to $240 million - net of $156 million of cash collateral and $41 million of letters of credit collateral provided to counterparties. Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions. Various contracts include credit enhancements in the form of cash collateral, letters of credit or other security in the event of a reduction in credit rating. Requirements of these provisions vary and typically require more than one rating reduction to below investment grade by S&P or Moody's to trigger additional collateralization. On July 15, 2004, FirstEnergy received $289 million of cash (principal and interest) for maturing OE certificates of deposit. These certificates of deposit related to OE's Beaver Valley Unit 2 sale and leaseback financing. Cash collateralized letters of credit associated with that financing were cancelled and replaced by unsecured letters of credit totaling approximately $237 million during the second quarter of 2004. FirstEnergy has also guaranteed the obligations of the operators of the TEBSA project in Colombia, up to a maximum of $6 million (subject to escalation) under the project's operations and maintenance agreement. In connection with the sale of TEBSA in January 2004, the purchaser indemnified FirstEnergy against any loss under this guarantee. FirstEnergy has provided the TEBSA project lenders a $60 million LOC, which is renewable and declines yearly based upon the senior outstanding debt of TEBSA. This LOC granted FirstEnergy the ability to sell its remaining 20.1% interest in Avon. OFF-BALANCE SHEET ARRANGEMENTS FirstEnergy has obligations that are not included on its Consolidated Balance Sheets related to the sale and leaseback arrangements involving Perry Unit 1, Beaver Valley Unit 2 and the Bruce Mansfield Plant. The present value of these sale and leaseback operating lease commitments, net of trust investments, total $1.4 billion as of June 30, 2004. CEI and TE sell substantially all of their retail customer receivables to CFC, a wholly owned subsidiary of CEI. CFC subsequently transfers the receivables to a trust (a "qualified special purpose entity" under SFAS 140) under an asset-backed securitization agreement. This arrangement provided $178 million of off-balance sheet financing as of June 30, 2004. FirstEnergy has equity ownership interests in various businesses that are accounted for using the equity method. There are no undisclosed material contingencies related to these investments. Certain guarantees that FirstEnergy does not expect to have a material current or future effect on its financial condition, liquidity or results of operations are disclosed under contractual obligations above. MARKET RISK INFORMATION FirstEnergy uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy's Risk Policy Committee, comprised of executive 46 officers, exercises an independent risk oversight function to ensure compliance with corporate risk management policies and prudent risk management practices. Commodity Price Risk FirstEnergy is exposed to market risk primarily due to fluctuating electricity, natural gas, coal, nuclear fuel and emission allowance prices. To manage the volatility relating to these exposures, it 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 much lesser extent, for trading purposes. Most of FirstEnergy's non-hedge derivative contracts represent non-trading positions that do not qualify for hedge treatment under SFAS 133. The change in the fair value of commodity derivative contracts related to energy production during the second quarter and first six months of 2004 is summarized in the following table: Increase (Decrease) in the Fair Value Of Commodity Derivative Contracts

(1) Includes $59 million in non-hedge commodity derivative contracts which are offset by a regulatory liability. (2) Interest rate swaps are treated as fair value hedges. Changes in derivative values are offset by changes in the hedged debts' premium or discount. (3) Represents the increase in value of existing contracts, settled contracts and changes in techniques/assumptions. Derivatives are included on the Consolidated Balance Sheet as of June 30, 2004 as follows: Non-Hedge Hedge Total ---------------------------------------------------------------------- (In millions) Current- Other Assets...................... $ 9 $ 6 $ 15 Other Liabilities................. (8) -- (8) Non-Current- Other Deferred Charges............ 61 2 63 Other Liabilities................. -- (51) (51) ---------------------------------------------------------------------- Net assets........................ $ 62 $(43) $ 19 ====================================================================== The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, FirstEnergy relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. FirstEnergy uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for the valuation of commodity derivative contracts by year are summarized in the following table: 47

(1) For the last two quarters of 2004. (2) Exchange traded. (3) Broker quote sheets. (4) Includes $59 million in non-hedge commodity derivative contracts which are offset by a regulatory liability. FirstEnergy performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift (an increase or decrease depending on the derivative position) in quoted market prices in the near term on both FirstEnergy's trading and nontrading derivative instruments would not have had a material effect on its consolidated financial position (assets, liabilities and equity) or cash flows as of June 30, 2004. Based on derivative contracts held as of June 30, 2004, an adverse 10% change in commodity prices would decrease net income by approximately $1 million during the next twelve months. Interest Rate Swap Agreements During the second quarter of 2004, FirstEnergy entered into fixed-to-floating interest rate swap agreements, as part of its ongoing effort to manage the interest rate risk of its debt portfolio. These derivatives are treated as fair value hedges of fixed-rate, long-term debt issues - protecting 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 and interest payment dates match those of the underlying obligations. As a result of the differences between fixed and variable debt rates, interest expense was $9 million lower in the second quarter of 2004, compared to being $8 million lower in the second quarter of 2003. As of June 30, 2004, the debt underlying the interest rate swaps had a weighted average fixed interest rate of 5.53%, which the swaps have effectively converted to a current weighted average variable interest rate of 2.66%.

(1) FirstEnergy no longer had the cash flow hedges as of January 30, 2004 as a result of the divestiture of Los Amigos Leasing Company, Ltd. - a subsidiary of GPU Power. Equity Price Risk Included in nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $851 million and $779 million as of June 30, 2004 and December 31, 2003, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in an $85 million reduction in fair value as of June 30, 2004. 48 CREDIT RISK Credit risk is the risk of an obligor's failure to meet the terms of any investment contract, loan agreement or otherwise perform as agreed. Credit risk arises from all activities in which success depends on issuer, borrower or counterparty performance, whether reflected on or off the balance sheet. FirstEnergy engages in transactions for the purchase and sale of commodities including gas, electricity, coal and emission allowances. These transactions are often with major energy companies within the industry. FirstEnergy maintains stringent credit policies with respect to its counterparties to manage overall credit risk. This includes performing independent risk evaluations, actively monitoring portfolio trends and using collateral and contract provisions to mitigate exposure. As part of its credit program, FirstEnergy aggressively manages the quality of its portfolio of energy contracts evidenced by a current weighted average risk rating for energy contract counterparties of "BBB" (S&P). As of June 30, 2004, the largest credit concentration with any counterparty relationship was 7% - that counterparty is currently rated investment grade. OUTLOOK State Regulatory Matters In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry deregulation included similar provisions which are reflected in the EUOCs' respective state regulatory plans. However, despite these similarities, the specific approach taken by each state and for each of the EUOC varies. Those provisions include: o allowing the EUOC's electric customers to select their generation suppliers; o establishing PLR obligations to non-shopping customers in the EUOC's service areas; o allowing recovery of potentially stranded investment (or transition costs) not otherwise recoverable in a competitive generation market; o itemizing (unbundling) the price of electricity into its component elements - including generation, transmission, distribution and stranded costs recovery charges; o deregulating the EUOC's electric generation businesses; o continuing regulation of the EUOC's transmission and distribution systems; and o requiring corporate separation of regulated and unregulated business activities. Regulatory assets are costs which the respective regulatory agencies have authorized for recovery (or to be requested for authorization in the case of ATSI) from customers in future periods and, without such authorization, would have been charged to income when incurred. All of the regulatory assets are expected to continue to be recovered under the provisions of the respective transition and regulatory plans as discussed below. The regulatory assets of the individual companies are as follows: June 30, December 31, Increase Regulatory Assets 2004 2003 (Decrease) --------------------------------------------------------------------- (In millions) OE..................... $1,267 $1,451 $(184) CEI.................... 1,001 1,056 (55) TE..................... 416 459 (43) Penn................... 8 28 (20) JCP&L.................. 2,324 2,558 (234) Met-Ed................. 946 1,028 (82) Penelec................ 411 497 (86) ATSI................... 11 - 11 ------------------------------------------------------------------- Total.................. $6,384 $7,077 $(693) ==================================================================== 49 Regulatory assets by source are as follows: June 30, December 31, Increase Regulatory Assets By Source 2004 2003 (Decrease) ------------------------------------------------------------------------------ (In millions) Regulatory transition charge................$5,688 $6,427 $(739) Customer shopping incentives................ 465 371 94 Customer receivables for future income taxes 300 340 (40) Societal benefits charge.................... 87 81 6 Loss on reacquired debt..................... 80 75 5 Postretirement benefits..................... 71 77 (6) Nuclear decommissioning, decontamination and spent fuel disposal costs............. (86) (96) 10 Component removal costs..................... (333) (321) (12) Property losses and unrecovered plant costs. 60 70 (10) Other....................................... 52 53 (1) ------------------------------------------------------------------------------ Total $6,384 $7,077 $(693) =============================================================================== Reliability Initiatives On October 15, 2003, NERC issued a letter to all NERC control areas and reliability coordinators requesting that a review of various reliability practices be undertaken within 60 days. The Company issued its response on December 15, 2003, confirming that its review had taken place and noted that it was undertaking various enhancements to current practices. On February 10, 2004, NERC issued its Recommended Actions to Prevent and Mitigate the Impacts of Future Cascading Blackouts. Approximately 20 of the recommendations were directed at the FirstEnergy companies and broadly focused on initiatives that were recommended for completion by June 30, 2004. These initiatives principally related to: changes in voltage criteria and reactive resources management; operational preparedness and action plans; emergency response capabilities; and preparedness and operating center training. FirstEnergy presented a detailed implementation plan to NERC, which the NERC Board of Trustees subsequently endorsed on May 7, 2004. The various initiatives required by NERC to be completed by June 30, 2004 have been certified as complete to NERC (on June 30, 2004), with one minor exception related to reactive testing of certain generators expected to be completed later this year. An independent NERC verification team conducted an on-site review of the completion status, reporting on July 14, 2004, that FirstEnergy had implemented the policies, procedures and actions that were recommended to be completed by June 30, 2004, with the exception noted by FirstEnergy. Implementation of the recommendations has not required incremental material investment or upgrades to existing equipment. On February 26 and 27, 2004, certain FirstEnergy companies participated in a NERC Control Area Readiness Audit. This audit, part of an announced program by NERC to review control area operations throughout much of the United States during 2004, was an independent review to identify areas recommended for reliability improvement. The final audit report was completed on May 6, 2004. The report identified positive observations and included various recommendations for reliability improvement. FirstEnergy implemented the audit results and recommendations relating to summer 2004 and 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 finalized later this year. 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 5, 2004, the U.S. - Canada Power System Outage Task Force issued a Final Report on the August 14, 2003 power outage. 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 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 recommendations on June 30, 2004. Implementation of the recommendations has not required incremental material investment or upgrades to existing equipment. 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 summer 2004 and 2009. FirstEnergy is continuing to review the results of that study related to 2009 and completed the implementation of recommendations relating to 2004 by June 30, 2004. Based on its review thus far, FirstEnergy believes that the study does not recommend any incremental material investment or upgrades to existing equipment. FirstEnergy notes, 50 however, that 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. 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 thereafter assembled an independent verification team to confirm implementation of NERC Recommended Actions to Prevent and Mitigate the Impacts of Future Cascading Blackouts required to be completed by June 30, 2004, as well as NERC recommendations contained in the Control Area Readiness Audit Report required to be completed by summer 2004, and recommendations in the Joint U.S. Canada Power System Outage Task Force Report directed toward FirstEnergy and required to be completed by June 30, 2004. The NERC 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. On July 5, 2003, JCP&L experienced a series of 34.5 kilo-volt 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 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. JCP&L expects to spend $12.5 million implementing these actions during 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. JCP&L is awaiting the final NJBPU order. 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. Discovery has commenced in the proceeding and Met-Ed's, Penelec's and Penn's testimony was filed May 7, 2004. On June 21, 2004, intervenors filed rebuttal testimony and Met-Ed's, Penelec's and Penn's surrebuttal testimony was filed on July 23, 2004. Hearings were held in early August 2004 and the ALJ has been directed to issue a Recommended Decision by September 30, 2004, in order to allow the PPUC time to issue a Final Order by the end of 2004. FirstEnergy is unable to predict the outcome of the investigation or the impact of the PPUC order. Ohio FirstEnergy's transition plan for the Ohio EUOC included approval for recovery of transition costs, including regulatory assets, 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; granting 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 EUOC retail customers; and freezing customer prices through a five-year market development period (2001-2005), except for certain limited statutory exceptions including a 5% reduction in the price of generation for residential customers. The Ohio EUOC 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. 51 On October 21, 2003, the Ohio EUOC 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: o A competitive auction, which would establish a price for generation that customers would be charged during the period covered by the auction, or o A Rate Stabilization Plan, which would extend current generation prices through 2008, ensuring adequate generation supply at stable prices, and continuing the Ohio EUOC's support of energy efficiency and economic development efforts. Under that proposal, the Ohio EUOC requested: o 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; o Deferral of interest costs on the accumulated shopping incentives and other cost deferrals as new regulatory assets; and o 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, FirstEnergy 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 FirstEnergy's revised Rate Stabilization Plan application. Among the major modifications were the following: o Limiting the ability of the Ohio EUOC to request adjustments in generation charges during 2006 through 2008 for increases in taxes; o Expanding the availability of market support generation; o Revising the kilowatt-hour target level and the time period for recovering regulatory transition charges; o Establishing a 3-year competitive bid process for generation; o Establishing the 2005 generation credit for shopping customers, which would be extended as a cap through 2008; and o Denying the ability to defer costs for future recovery of distribution reliability improvement expenditures. On June 18, 2004, the Ohio EUOC 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: o Expanding the Ohio EUOC's 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; o Approving the revised kilowatt-hour target level and time period for recovery of regulatory transition costs as presented by the Ohio EUOC in their rehearing application; o Retaining the requirement for expanded availability of market support generation, but adopting the Ohio EUOC's alternative approach that conditions expanded availability on higher pricing and eliminating the requirement to reduce the interest deferral for certain affected rate schedules; 52 o Revising the calculation of the shopping credit cap for certain commercial and small industrial rate schedules; and o Relaxing the notice requirement for availability of enhanced shopping credits in a number of instances. On August 5, 2004, FirstEnergy accepted the Rate Stabilization Plan as modified and approved by the PUCO on August 4, 2004. FirstEnergy retains 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 EUOC 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. New Jersey 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, JCP&L would initiate another proceeding to request recovery of additional costs incurred to enhance system reliability. In that proceeding, the NJBPU could increase the 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 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 charge. The MTC allows for the recovery of $465 million in deferred energy costs over the next ten years on an interim basis, thus disallowing $153 million of the $618 million provided for in a preliminary settlement agreement between certain parties. 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 disallowed deferred energy costs and other regulatory assets. JCP&L filed a 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 NJBPU 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 costs disallowances, (2) the capital structure including the rate of return, (3) merger savings, (4) amortization of costs to achieve merger savings; and (5) decommissioning. All other issues included in JCP&L's amended motion were denied. Oral arguments were held on August 4, 2004. Management cannot predict when a decision following the oral arguments may be announced by the NJBPU. 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 higher return on equity. The filing also requests an increase to the MTC deferred balance recovery of approximately $20 million annually. 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. 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 JCP&L's customers without a reduction, termination or capping of the funding. Pennsylvania 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 reversed 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 53 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. 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 ALJ 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 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 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 retroactive 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, one 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. 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. The EPA has proposed the Interstate Air Quality Rule to "cap-and-trade" NOx 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 54 reductions ultimately reaching more than 5.5 million tons annually. NOx 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 may be substantial and will depend on whether and how they are ultimately implemented by the states in which the Companies operate affected facilities. 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 "maximum achievable control technologies" (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 NOx 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. In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a Compliance Order 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 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 June 30, 2004. 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. Power Outages 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. Since July 1999, this litigation has involved a substantial amount of legal discovery including interrogatories, request for production of documents, preservation and inspection of evidence, and depositions of the named plaintiffs and many JCP&L employees. In addition, there have been many motions filed and argued by the parties involving issues such as the primary jurisdiction and findings of the NJBPU, consumer fraud by JCP&L, strict product liability, class decertification, and the damages claimed by the plaintiffs. In January 2000, the NJ Appellate Division determined that the trial court has proper jurisdiction over this litigation. 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 55 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 July 28, 2004, both plaintiffs and JCP&L appealed the decision of the Appellate Division to the New Jersey Supreme Court. FirstEnergy is unable to predict the outcome of these matters and no liability has been accrued as of June 30, 2004. On August 14, 2003, various states and parts of southern Canada experienced a widespread power outage. That outage 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 this outage. In the final report, the Task Force concluded, among other things, that the problems leading to the outage began in FirstEnergy's Ohio service area. Specifically, the final report concludes, among other things, that the initiation of the August 14th power outage resulted from the coincidence on that afternoon of several events, including: 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 14th power outage and that it does not adequately address the underlying causes of the outage. FirstEnergy remains convinced that the outage cannot be explained by events on any one utility's system. 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 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 14th power outage, 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 above). 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 June 30, 2004 for any expenditures in excess of those actually incurred through that date. Davis-Besse 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. As part of its informal inquiry, which began in September 2003, the SEC's Division of Enforcement requested on June 24, 2004 that FirstEnergy voluntarily provide information and documents related to the Davis-Besse outage. FirstEnergy is complying with this request and continues to cooperate fully with this inquiry. If it were ultimately determined that FirstEnergy has legal liability or is otherwise made subject to enforcement action based on any of the above matters with respect to the Davis-Besse outage, it could have a material adverse effect on FirstEnergy's financial condition and results of operations. 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. 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 its Ohio utility subsidiaries of previously reported results, the August 14th power outage described above, and the extended outage at the Davis-Besse Nuclear Power 56 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 a charge against FirstEnergy's second quarter 2004 earnings of $0.03 per share of common stock. The federal securities cases were consolidated into a single action, as were the federal derivative cases; those actions are pending in federal court in Akron. Two state court derivative cases are also pending. The settlement is subject to court approval and, 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. FirstEnergy's Ohio utility subsidiaries were named as respondents in two regulatory proceedings initiated at the PUCO in response to complaints alleging failure to provide reasonable and adequate service stemming primarily from the August 14th power outage. 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 them. In particular, if FirstEnergy were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on its financial condition and results of operations. 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 outage. All three cases were dismissed for lack of jurisdiction. One case was refiled at the PUCO and the other two have been appealed. CRITICAL ACCOUNTING POLICIES FirstEnergy prepares its consolidated financial statements in accordance with GAAP. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. All of FirstEnergy's assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. FirstEnergy's more significant accounting policies are described below. Regulatory Accounting FirstEnergy's regulated services segment is subject to regulation that sets the prices (rates) it is permitted to charge its customers based on costs that the regulatory agencies determine FirstEnergy is permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. FirstEnergy regularly reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. Derivative Accounting Determination of appropriate accounting for derivative transactions requires the involvement of management representing operations, finance and risk assessment. In order to determine the appropriate accounting for derivative transactions, the provisions of the contract need to be carefully assessed in accordance with the authoritative accounting literature and management's intended use of the derivative. New authoritative guidance continues to shape the application of derivative accounting. Management's expectations and intentions are key factors in determining the appropriate accounting for a derivative transaction and, as a result, such expectations and intentions are documented. Derivative contracts that are determined to fall within the scope of SFAS 133, as amended, must be recorded at their fair value. Active market prices are not always available to determine the fair value of the later years of a contract, requiring that various assumptions and estimates be used in their valuation. FirstEnergy continually monitors its derivative contracts to determine if its activities, expectations, intentions, assumptions and estimates remain valid. As part of its normal operations, FirstEnergy enters into a significant number of commodity contracts, as well as interest rate swaps, which increase the impact of derivative accounting judgments. Revenue Recognition FirstEnergy follows the accrual method of accounting for revenues, recognizing revenue for electricity that has been delivered to customers but not yet billed through the end of the accounting period. The determination of electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimated and a corresponding accrual for unbilled revenues is recognized. The determination of unbilled revenues requires management to make estimates regarding electricity available for retail load, transmission and distribution line losses, demand by customer class and electricity provided by alternative suppliers. 57 Pension and Other Postretirement Benefits Accounting FirstEnergy's reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions FirstEnergy makes to the plans, and earnings on plan assets. Such factors may be further affected by business combinations (such as FirstEnergy's merger with GPU in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs are also affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. In accordance with SFAS 87 and SFAS 106, changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. FirstEnergy reduced its assumed discount rate as of December 31, 2003 to 6.25% from 6.75% used as of December 31, 2002. FirstEnergy's assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. In 2003 and 2002, plan assets actually earned 24.0% and (11.3)%, respectively. FirstEnergy's pension costs in 2003 and the first half of 2004 were computed assuming a 9.0% rate of return on plan assets based upon projections of future returns and its pension trust investment allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash. Based on pension assumptions and pension plan assets as of December 31, 2003, FirstEnergy is not required to fund its pension plans in 2004. Health care cost trends have significantly increased and will affect future OPEB costs. The 2004 and 2003 composite health care trend rate assumptions are approximately 10%-12% gradually decreasing to 5% in later years. In determining its trend rate assumptions, FirstEnergy included the specific provisions of its health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in its health care plans, and projections of future medical trend rates. Ohio Transition Cost Amortization In connection with FirstEnergy's initial transition plan, the PUCO determined allowable transition costs based on amounts recorded on the regulatory books of the Ohio electric utilities. These costs exceeded those deferred or capitalized on FirstEnergy's balance sheet prepared under GAAP since they included certain costs which have not yet been incurred or that were recognized on the regulatory financial statements (fair value purchase accounting adjustments). FirstEnergy uses an effective interest method for amortizing its transition costs, often referred to as a "mortgage-style" amortization. The interest rate under this method is equal to the rate of return authorized by the PUCO in the Rate Stabilization Plan for each respective company. In computing the transition cost amortization, FirstEnergy includes only the portion of the transition revenues associated with transition costs included on the balance sheet prepared under GAAP. Revenues collected for the off balance sheet costs and the return associated with these costs are recognized as income when received. Long-Lived Assets In accordance with SFAS 144, FirstEnergy periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset might not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment has occurred, FirstEnergy recognizes a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). The calculation of future cash flows is based on assumptions, estimates and judgment about future events. The aggregate amount of cash flows determines whether an impairment is indicated. The timing of the cash flows is critical in determining the amount of the impairment. 58 Nuclear Decommissioning In accordance with SFAS 143, FirstEnergy recognizes an ARO for the future decommissioning of its nuclear power plants. The ARO liability represents an estimate of the fair value of FirstEnergy's current obligation related to nuclear decommissioning and the retirement of other assets. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. FirstEnergy used an expected cash flow approach (as discussed in FCON 7) to measure the fair value of the nuclear decommissioning ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. The scenarios consider settlement of the ARO at the expiration of the nuclear power plants' current license and settlement based on an extended license term. Goodwill In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, FirstEnergy evaluates 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 most recent annual review was completed in the third quarter of 2003. As a result of that review, a non-cash goodwill impairment charge of $122 million was recognized in the third quarter of 2003, reducing the carrying value of FSG. The forecasts used in FirstEnergy's evaluations of goodwill reflect operations consistent with its general business assumptions. Unanticipated changes in those assumptions could have a significant effect on FirstEnergy's future evaluations of goodwill. In the first half of 2004, FirstEnergy reduced goodwill by $27 million for pre-merger interest received on an income tax refund and other tax benefits. As of June 30, 2004, FirstEnergy had $6.1 billion of goodwill that primarily relates to its regulated services segment. 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 During 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. The new standard, as proposed, would be effective January 1, 2005, for calendar year companies. FirstEnergy will not be able to determine the exact impact of the proposed standard on its results of operations until the standard is issued in final form. The impact of the fair value recognition provisions of SFAS 123 on FirstEnergy's net income and earnings per share for the current reporting periods is disclosed in Note 2. EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary and Its Application to Certain Investments" On March 31, 2004, the FASB ratified the consensus reached by the EITF 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 are to be applied to other-than-temporary impairment evaluations in reporting periods beginning after June 15, 2004. FirstEnergy has available-for-sale securities with unrealized losses of approximately $21 million as of June 30, 2004 that will be evaluated in accordance with EITF 03-1 in the third quarter of 2004. EITF Issue No. 03-6, "Participating Securities and the Two-Class Method Under Financial Accounting Standards Board Statement No. 128, Earnings per Share" On March 31, 2004, the FASB ratified the consensus reached by the EITF on Issue 03-6. The issue addresses a number of questions regarding the computation of earnings per share by companies that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of a company when, and if, it declares dividends on its common stock. The issue also provides further guidance in applying the two-class method of computing earnings per share once it is determined that a security is participating, including how to allocate undistributed earnings to such a security. EITF 03-6 was effective for fiscal periods beginning after March 31, 2004 and had no impact on FirstEnergy's computation of earnings per share. 59 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. 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 FirstEnergy's consolidated financial statements. 60 OHIO EDISON COMPANY CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (Unaudited)

OHIO EDISON COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited)

OHIO EDISON COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Stockholders and Board of Directors of Ohio Edison Company: We have reviewed the accompanying consolidated balance sheet of Ohio Edison Company and its subsidiaries as of June 30, 2004, and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and six-month periods ended June 30, 2004 and 2003. These interim financial statements are the responsibility of the Company's management. We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America. We previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet and the consolidated statement of capitalization as of December 31, 2003, and the related consolidated statements of income, common stockholder's equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company's change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 1(F) to those consolidated financial statements and the Company's change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 6 to those consolidated financial statements) dated February 25, 2004 we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2003, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived. PricewaterhouseCoopers LLP Cleveland, Ohio August 6, 2004 64 OHIO EDISON COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION OE is a wholly owned, electric utility subsidiary of FirstEnergy. OE and its wholly owned subsidiary, Penn, conduct business in portions of Ohio and Pennsylvania, providing regulated electric distribution services. OE and Penn (OE Companies) also provide generation services to those customers electing to retain them as their power supplier. The OE Companies provide power directly to wholesale customers under previously negotiated contracts, as well as to some alternative energy suppliers under OE's transition plan. The OE Companies have unbundled the price of electricity into its component elements - including generation, transmission, distribution and transition charges. Power supply requirements of the OE Companies are provided by FES -- an affiliated company. Results of Operations --------------------- Earnings on common stock in the second quarter of 2004 increased to $87 million from $45 million in the second quarter of 2003. During the first six months of 2004, earnings on common stock increased to $162 million from $133 million in the same period of 2003. In the first six months of 2003, earnings on common stock included an after-tax credit of $32 million from the cumulative effect of an accounting change due to the adoption of SFAS 143. Income before the cumulative effect was $102 million in the first six months of 2003. Results in the second quarter and the first six months of 2004, compared to the same periods in 2003, improved due to higher operating revenues, reduced financing costs and lower nuclear operating expenses as a result of additional outage-related work at the nuclear generating plants in 2003. Partially offsetting these improvements were increased purchased power costs, higher nuclear fuel expenses and increased other operating costs. Operating revenues increased by $44.6 million or 6.6% in the second quarter of 2004 compared with the same period in 2003. The higher revenues primarily resulted from additional wholesale sales to FES ($28.6 million) due to increased nuclear generation available for sale, partially offset by lower revenues from nonaffiliate wholesale customers ($7.7 million) principally due to the expiration of a contract in July 2003. The increased nuclear generation in 2004 was due to refueling outages last year at Beaver Valley Unit 1 and Perry. Contributing to the increase in revenues were higher retail generation sales which increased revenues by $14.8 million. Kilowatt-hour sales to retail customers increased by 7.0% due to a stronger economy in OE's service area, the decline of sales by alternative suppliers as a percentage of total sales (1.7 percentage points) and warmer weather in the second quarter 2004. In the first six months of 2004, operating revenues increased by $45.2 million or 3.2%. Revenues from wholesale sales to FES increased by $44.5 million, which were partially offset by the expired contract that reduced wholesale revenues by $11 million. Retail generation sales revenues increased by $12.3 million reflecting the effect of increased unit prices and increased sales in the commercial and industrial customer sectors, partially offset by lower residential sales. The increased consumption for the first half of 2004 was primarily due to a stronger economy and warmer weather in the second quarter of 2004. Distribution deliveries increased 4.5% in the second quarter of 2004 and 1.2% in the first six months of 2004 compared with the corresponding periods of 2003 with increases in all retail customer categories. Revenues from electricity throughput increased by $11.4 million in the second quarter and $5.5 million in the first half of 2004 compared to the same periods of 2003. Changes in electric generation sales and distribution deliveries in the second quarter and first six months of 2004 from the corresponding periods of 2003 are summarized in the following table: Changes in Kilowatt-Hour Sales Three Months Six Months -------------------------------------------------------------------- Increase (Decrease) Electric Generation: Retail............................... 7.0% 1.3% Wholesale............................ 25.3% 16.5% ------------------------------------------------------------------ Total Electric Generation Sales........ 15.3% 8.1% ================================================================== Distribution Deliveries: Residential.......................... 7.8% 1.8% Commercial........................... 5.3% 2.2% Industrial........................... 1.7% -- ------------------------------------------------------------------- Total Distribution Deliveries.......... 4.5% 1.2% ================================================================== 65 Operating Expenses and Taxes Total operating expenses and taxes increased $22 million in the second quarter and $11 million in the first six months of 2004 from the same periods last year. The following table presents changes from the prior year by expense category. Operating Expenses and Taxes - Changes Three Months Six Months ---------------------------------------------------------------------------- Increase (Decrease) (In millions) Fuel............................................ $ 4 $ 6 Purchased power costs........................... 22 28 Nuclear operating costs......................... (41) (90) Other operating costs........................... 12 7 ------------------------------------------------------------------------ Total operation and maintenance expenses...... (3) (49) Provision for depreciation and amortization..... (1) 16 General taxes................................... (5) (5) Income taxes.................................... 31 49 ------------------------------------------------------------------------ Net increase in operating expenses and taxes.. $ 22 $ 11 ======================================================================== Higher fuel costs in the second quarter and first six months of 2004, compared with the same periods of 2003, resulted from increased nuclear generation - up 45.8% and 33.2%, respectively. Purchased power costs were higher in both periods of 2004 reflecting higher unit costs and increased kilowatt-hour purchases from FES for supply to PLR customers. Lower nuclear operating costs occurred in large part due to the absence of refueling outages in 2004 - refueling outages were performed at Beaver Valley Unit 1 (100% ownership) in the first quarter of 2003 and the Perry plant (35.24% ownership) in the second quarter of 2003. The increase in other operating costs in the second quarter and first six months of 2004, compared to the same periods of 2003, is due to higher employee benefit costs and administrative costs. Depreciation and amortization increased by $16 million in the first six months of 2004 compared to the same period of 2003 primarily from four factors - increased amortization of Ohio transition regulatory assets ($17 million) and decreased regulatory asset deferrals ($3 million), partially offset by higher shopping incentive deferrals ($0.9 million) and the deferral of interest costs on accumulated deferred shopping incentives ($5 million). The interest deferrals were implemented in the second quarter of 2004 (retroactive to January 1, 2004) pursuant to the Ohio Rate Stabilization Plan. General taxes decreased in the second quarter and first six months of 2004 from the same periods of 2003 primarily due to refunds received on a real estate valuation settlement ($6 million). Net Interest Charges Net interest charges continued to trend lower, decreasing by $15 million in the second quarter and $22 million in the first six months of 2004 from the same periods last year, reflecting redemptions and refinancings since June 30, 2003. OE's net debt redemptions totaled $28 million during the first six months of 2004, which will result in annualized savings of $2 million. Cumulative Effect of Accounting Change Upon adoption of SFAS 143 in the first quarter of 2003, OE recorded an after-tax credit to net income of $32 million. The cumulative adjustment for unrecognized depreciation, accretion offset by the reduction in the existing decommissioning liabilities and ceasing the accounting practice of depreciating non-regulated generation assets using a cost of removal component was a $54 million increase to income, or $32 million net of income taxes. Capital Resources And Liquidity ------------------------------- OE's cash requirements in 2004 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing its net debt and preferred stock outstanding. Available borrowing capacity under short-term credit facilities will be used to manage working capital requirements. Over the next two years, OE expects to meet its contractual obligations with cash from operations. Thereafter, OE expects to use a combination of cash from operations and funds from the capital markets. Changes in Cash Position There was no change as of June 30, 2004 and December 31, 2003 in OE's cash and cash equivalents of $2 million. 66 Cash Flows From Operating Activities Cash provided by operating activities during the second quarter and first six months of 2004, compared with the corresponding periods in 2003 were as follows: Three Months Ended Six Months Ended June 30, June 30, ------------------ ------------------- Operating Cash Flows 2004 2003 2004 2003 ---------------------------------------------------------------------------- (In millions) Cash earnings (1)............ $ 152 $101 $ 383 $284 Working capital and other.... (252) (34) (371) (63) ---------------------------------------------------------------------------- Total........................ $(100) $ 67 $ 12 $221 ---------------------------------------------------------------------------- (1) Includes net income, depreciation and amortization, deferred income taxes, investment tax credits and major noncash charges. Net cash from operating activities decreased $167 million in the second quarter of 2004 due to a $218 million decrease from changes in working capital partially offset by a $51 million increase in cash earnings. The change in working capital primarily reflects lower accounts payable and an increase in accounts receivable from associated companies. A decrease in accrued tax liabilities also contributed $74 million to the change in working capital primarily due to an increase in estimated tax payments in the second quarter of 2004 compared with the second quarter of 2003. Net cash from operating activities decreased $209 million in the first six months of 2004 due to a $308 million decrease from changes in working capital partially offset by a $99 million increase in cash earnings. The change in working capital primarily reflects higher accounts receivable and decreases in accounts payable and accrued taxes, reflecting changes of $249 million for the reallocation of tax liabilities between associated companies related to the tax sharing agreement. The increase in cash earnings in both periods resulted from higher operating revenues and decreased nuclear operating costs. Cash Flows From Financing Activities In the second quarter of 2004, net cash used for financing activities was $232 million, compared to net cash provided from financing activities of $77 million in the second quarter of 2003. The change resulted from new financing in 2003 partially offset by a net decrease from short-term borrowings. Common stock dividend payments to FirstEnergy decreased by $155 million in the second quarter of 2004 compared to the second quarter of 2003. In the first six months of 2004, net cash used for financing activities increased to $337 million from $188 million in the same period last year. The increase resulted from reduced new financings in 2004 offset by lower payments on short-term borrowings and reduced common stock dividends to FirstEnergy. On June 7, 2004, OE replaced certain collateralized letters of credit that were issued in 1994 in support of OE's obligations to lessors under the Beaver Valley Unit 2 sale and leaseback arrangements. Approximately $289 million in cash collateral and accrued interest previously held by OES Finance Incorporated, a wholly owned subsidiary of OE, was released on July 15, 2004 upon cancellation of the existing letters of credit and was used to repay short-term debt and for other corporate purposes. Simultaneously with the issuance of the replacement letters of credit, OE entered into a Credit Agreement pursuant to which a standby letter of credit was issued in support of the replacement letters of credit, and the issuer of the letters of credit obtained the right to pledge or assign participations in OE's reimbursement obligations to a trust. The trust then issued and sold trust certificates to institutional investors that were designed to be the credit equivalent of an investment directly in OE. OE had approximately $259 million of cash and temporary investments (which include short-term notes receivable from associated companies) and approximately $105 million of short-term indebtedness as of June 30, 2004. Available borrowing capability under bilateral bank facilities totaled $34 million as of June 30, 2004. The OE Companies had the capability to issue $2 billion of additional first mortgage bonds on the basis of property additions and retired bonds. Based upon applicable earnings coverage tests the OE Companies could issue up to $3.1 billion of preferred stock (assuming no additional debt was issued) as of June 30, 2004. OE's $125 million 364-day revolving credit facility was restructured through a new syndicated FirstEnergy facility that was completed on June 22, 2004. Combined with an existing syndicated $125 million three-year facility for OE maturing in October 2006, an existing syndicated $250 million two-year facility for OE maturing in May 2005 and bank facilities of $34 million, OE's credit facilities total $409 million, which was unused as of June 30, 2004. These facilities are intended to provide liquidity to meet the short-term working capital requirements of OE and its regulated affiliates. 67 Borrowings under these facilities are conditioned on OE maintaining compliance with certain financial covenants in the agreements. OE, under its $125 million 364-day and $250 million two-year facilities, is required to maintain a debt to total capitalization ratio of no more than 0.65 to 1 and a contractually-defined fixed charge coverage ratio of no less than 2 to 1. OE is in compliance with these financial covenants. As of June 30, 2004, OE's fixed charge coverage ratio, as defined under the credit agreements, was 6.84 to 1. OE's debt to total capitalization ratio, as defined under the credit agreements, was 0.38 to 1. The ability to draw on these facilities is also conditioned upon OE making certain representations and warranties to the lending banks prior to drawing on its facilities, including a representation that there has been no material adverse change in its business, its condition (financial or otherwise), its results of operations, or its prospects. OE's primary credit facilities contains no provisions restricting its ability to borrow, or accelerating repayment of outstanding loans, under the facilities accelerated, as a result of any change in the credit ratings of OE by any of the nationally-recognized rating agencies. The primary facilities do contain "pricing grids", whereby the cost of funds borrowed under the facilities is related to the credit ratings of the company borrowing the funds. OE has the ability to borrow from its regulated affiliates and FirstEnergy to meet its short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries, as well as proceeds available from bank borrowings. Available bank borrowings include $1.75 billion from FirstEnergy's and OE's revolving credit facilities. Companies receiving a loan under the money pool agreements must repay the principal amount of such a loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the second quarter of 2004 was 1.39%. In March 2004, Penn completed a receivables financing arrangement that provides borrowing capability of up to $25 million. The borrowing rate is based on bank commercial paper rates. Penn is required to pay an annual facility fee of 0.40% on the entire finance limit. The facility was undrawn as of June 30, 2004 and matures on March 29, 2005. On April 1, 2004, $33 million Ohio Water Development Authority 1988 Series B pollution control revenue refunding bonds and $23 million Ohio Air Quality Development Authority 1988 Series C pollution control revenue refunding bonds were remarketed and converted to a daily interest rate mode, and separate letters of credit in support of principal and interest payments on each issue of bonds were issued. Simultaneously with these remarketings, the issuer of the letters of credit also extended certain existing letters of credit supporting $50 million Ohio Air Quality Development Authority 1989 Series A pollution control revenue refunding bonds and $50 million Ohio Air Quality Development Authority Series 2000-C pollution control revenue refunding bonds. On June 1, 2004, $108 million Beaver County Industrial Development Authority Series 1999-A pollution control revenue refunding bonds were remarketed and converted to an auction rate interest mode, insured with municipal bond insurance and secured with first mortgage bonds. OE's access to capital markets and costs of financing are dependent on the ratings of its securities and the securities of OE and FirstEnergy. The ratings outlook on all securities is stable. On April 28, 2004, Moody's published a Liquidity Risk Assessment of FirstEnergy Corp. stating that FirstEnergy had "adequate liquidity." Moody's noted that FirstEnergy's committed credit facilities at the holding company level provided a substantial source of liquidity. Moody's also noted that, in the past year, FirstEnergy had lengthened the average maturity of its bank facilities and had made reductions to its total consolidated debt level. On April 30, 2004, Moody's published a Credit Opinion of FirstEnergy Corp. Moody's cited the stable and predictable cash flows of FirstEnergy's core utility operations, management's focus on increasing financial flexibility via debt reduction and divestiture of non-core assets, FirstEnergy's integrated regional strategy, and strong liquidity as credit strengths. Moody's noted the substantial debt burden associated with the GPU merger, fully competitive generating markets, and modest growth in markets served as credit challenges for FirstEnergy. Moody's also noted that a "track record of improving financial condition, especially a track record of debt reduction, could cause the ratings to go up" and that the opposite development could cause the ratings to go down. On June 14, 2004, S&P stated that the June 9, 2004 PUCO decision on FirstEnergy's Rate Stabilization Plan did not affect the ratings or the outlook on FirstEnergy. On July 22, 2004, S&P updated its analysis of U.S. utility FMBs in response to changes in the industry. As a result of its revised methodology for evaluating default risk, S&P raised its FMB credit ratings for 20 U.S. utility companies including Penn. Penn's FMB credit rating was upgraded to BBB from BBB-. Cash Flows From Investing Activities Net cash provided from investing activities totaled $332 million in the first quarter of 2004 and $325 million for the first six months, compared to net cash of $156 million and $51 million, respectively, used for investing 68 activities for the same periods of 2003. The $488 million change for the second quarter and $376 million for the first six months, resulted primarily from net increases in loans from associated companies. During the last two quarters of 2004, capital requirements for property additions and capital leases are expected to be about $132 million, including $45 million for nuclear fuel. OE has additional requirements of approximately $53 million to meet sinking fund requirements for preferred stock and maturing long-term debt during the remainder of 2004. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. Off-Balance Sheet Arrangements ------------------------------ Obligations not included on OE's Consolidated Balance Sheet primarily consist of sale and leaseback arrangements involving Perry Unit 1 and Beaver Valley Unit 2. As of June 30, 2004, the present value of these sale and leaseback operating lease commitments, net of trust investments, total $680 million. Equity Price Risk ----------------- Included in OE's nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $225 million and $209 million as of June 30, 2004 and December 31, 2003, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $22 million reduction in fair value as of June 30, 2004. Outlook ------- Beginning in 2001, OE's customers were able to select alternative energy suppliers. OE continues to deliver power to residential homes and businesses through its existing distribution system, which remains regulated. Customer rates have been restructured into separate components to support customer choice. In Ohio and Pennsylvania, the OE Companies have a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier subject to certain limits. Adopting new approaches to regulation and experiencing new forms of competition have created new uncertainties Regulatory Matters Ohio Beginning on January 1, 2001, OE's customers were able to choose their electricity suppliers. Customer rates were restructured to establish separate charges for transmission, distribution, transition cost recovery and a generation-related component. When one of OE's customers elects to obtain power from an alternative supplier, OE reduces the customer's bill with a "generation shopping credit," based on the regulated generation component (plus an incentive), and the customer receives a generation charge from the alternative supplier. Under the recently approved Rate Stabilization Plan, OE has continuing PLR responsibility to its franchise customers through December 31, 2008. As part of OE's transition plan, it is obligated to supply electricity to customers who do not choose an alternative supplier. OE is also required to provide 560 MW of low cost supply to unaffiliated alternative suppliers who serve customers within its service area. FES acts as an alternate supplier for a portion of the load in OE's franchise area. On October 21, 2003, the Ohio EUOC 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: o A competitive auction, which would establish a price for generation that customers would be charged during the period covered by the auction, or o A Rate Stabilization Plan, which would extend current generation prices through 2008, ensuring adequate generation supply at stable prices, and continuing OE's support of energy efficiency and economic development efforts. Under that proposal, OE requested: o Extension of the transition cost amortization period for OE from 2006 to 2007; o Deferral of interest costs on the accumulated shopping incentives and other cost deferrals as new regulatory assets; and 69 o 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, OE 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 OE's revised Rate Stabilization Plan application. Among the major modifications were the following: o Limiting the ability of OE to request adjustments in generation charges during 2006 through 2008 for increases in taxes; o Expanding the availability of market support generation; o Revising the kilowatt-hour target level and the time period for recovering regulatory transition charges; o Establishing a 3-year competitive bid process for generation; o Establishing the 2005 generation credit for shopping customers, which would be extended as a cap through 2008; and o Denying the ability to defer costs for future recovery of distribution reliability improvement expenditures. On June 18, 2004, the Ohio EUOC 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: o Expanding OE's 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; o Approving the revised kilowatt-hour target level and time period for recovery of regulatory transition costs as presented by OE in its rehearing application; o Retaining the requirement for expanded availability of market support generation, but adopting OE's alternative approach that conditions expanded availability on higher pricing and eliminating the requirement to reduce the interest deferral for certain affected rate schedules; o Revising the calculation of the shopping credit cap for certain commercial and small industrial rate schedules; and o Relaxing the notice requirement for availability of enhanced shopping credits in a number of instances. On August 5, 2004, OE accepted the Rate Stabilization Plan as modified and approved by the PUCO on August 4, 2004. OE retains 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, OE 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) and the deferral of interest costs on the accumulated deferred shopping incentives. Regulatory Assets Regulatory assets are costs which have been authorized by the PUCO, PPUC and the FERC, for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. All of the OE Companies' regulatory assets are expected to continue to be recovered under the provisions of their respective transition plan and rate restructuring plans. The OE Companies' regulatory assets were as follows: 70 Regulatory Assets as of --------------------------------------------------------- June 30, December 31, Company 2004 2003 --------------------------------------------------------- (In millions) OE......................... $1,267 $1,450 Penn....................... 8 28 --------------------------------------------------------- Consolidated Total...... $1,275 $1,478 ========================================================= Reliability Initiatives On October 15, 2003, NERC issued a letter to all NERC control areas and reliability coordinators requesting that a review of various reliability practices be undertaken within 60 days. The Company issued its response on December 15, 2003, confirming that its review had taken place and noted that it was undertaking various enhancements to current practices. On February 10, 2004, NERC issued its Recommended Actions to Prevent and Mitigate the Impacts of Future Cascading Blackouts. Approximately 20 of the recommendations were directed at the FirstEnergy companies and broadly focused on initiatives that were recommended for completion by June 30, 2004. These initiatives principally related to: changes in voltage criteria and reactive resources management; operational preparedness and action plans; emergency response capabilities; and preparedness and operating center training. FirstEnergy presented a detailed implementation plan to NERC, which the NERC Board of Trustees subsequently endorsed on May 7, 2004. The various initiatives required by NERC to be completed by June 30, 2004 have been certified as complete to NERC (on June 30, 2004), with one minor exception related to reactive testing of certain generators expected to be completed later this year. An independent NERC verification team conducted an on-site review of the completion status, reporting on July 14, 2004, that FirstEnergy had implemented the policies, procedures and actions that were recommended to be completed by June 30, 2004, with the exception noted by FirstEnergy. Implementation of the recommendations has not required incremental material investment or upgrades to existing equipment. On February 26 and 27, 2004, OE participated in a NERC Control Area Readiness Audit. This audit, part of an announced program by NERC to review control area operations throughout much of the United States during 2004, was an independent review to identify areas recommended for reliability improvement. The final audit report was completed on May 6, 2004. The report identified positive observations and included various recommendations for reliability improvement. FirstEnergy implemented the audit results and recommendations relating to summer 2004 and 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 finalized later this year. Implementation of the recommendations has not required incremental material investment or upgrades to existing equipment. On March 1, 2004, OE filed, in accordance with a November 25, 2003 order from the PUCO, its 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 5, 2004, the U.S. - Canada Power System Outage Task Force issued a Final Report on the August 14, 2003 power outage. 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 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 recommendations on June 30, 2004. Implementation of the recommendations has not required incremental material investment or upgrades to existing equipment. 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 summer 2004 and 2009. FirstEnergy is continuing to review the results of that study related to 2009 and completed the implementation of recommendations relating to 2004 by June 30, 2004. Based on its review thus far, FirstEnergy believes that the study does not recommend any incremental material investment or upgrades to existing equipment. FirstEnergy notes, however, that 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. 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 thereafter assembled an independent verification team to confirm implementation of NERC Recommended Actions to Prevent and Mitigate the Impacts of Future Cascading Blackouts required to be completed by June 30, 2004, as well as NERC recommendations contained in the Control Area 71 Readiness Audit Report required to be completed by summer 2004, and recommendations in the Joint U.S. Canada Power System Outage Task Force Report directed toward FirstEnergy and required to be completed by June 30, 2004. The NERC 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. 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 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. 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. Penn is unable to predict the outcome of this proceeding. On January 16, 2004, the PPUC initiated a formal investigation of whether Penn's "service reliability performance deteriorated to a point below the level of service reliability that existed prior to restructuring" in Pennsylvania. Discovery has commenced in the proceeding and Penn's testimony was filed May 7, 2004. On June 21, 2004, intervenors filed rebuttal testimony and Penn's surrebuttal testimony was filed on July 23, 2004. Hearings were held in early August 2004 and the ALJ has been directed to issue a Recommended Decision by September 30, 2004, in order to allow the PPUC time to issue a Final Order by the end of 2004. Penn is unable to predict the outcome of the investigation or the impact of the PPUC order. Environmental Matters Various federal, state and local authorities regulate OE with regard to air and water quality and other environmental matters. The effects of compliance on OE with regard to environmental matters could have a material adverse effect on its earnings and competitive position. These environmental regulations affect OE'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, OE 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. OE is 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. OE cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a Compliance Order to nine utilities covering 44 power plants, including the W. H. Sammis Plant. 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 the OE Companies' 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 June 30, 2004. The OE 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. NOx reductions required by the 1990 Amendments are being 72 achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NOx reductions from the OE Companies' facilities. The EPA's NOx Transport Rule imposes uniform reductions of NOx emissions (an approximate 85% reduction in utility plant NOx 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 NOx emissions are contributing significantly to ozone levels in the eastern United States. State Implementation Plans (SIP) were required to comply by May 31, 2004 with individual state NOx budgets. Pennsylvania submitted a SIP that required compliance with the state NOx budgets at the OE Companies' Pennsylvania facilities by May 1, 2003. Ohio submitted a SIP that required compliance with the state NOx budgets at the OE Companies' Ohio facilities by May 31, 2004. The OE Companies believe their facilities are complying with the state NOx budgets through combustion controls and post-combustion controls, including Selective Catalytic Reduction and Selective Non-Catalytic Reduction systems, and/or using emission allowances. Power Outage On August 14, 2003, various states and parts of southern Canada experienced a widespread power outage. That outage 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 this outage. In the final report, the Task Force concluded, among other things, that the problems leading to the outage began in FirstEnergy's Ohio service area. Specifically, the final report concludes, among other things, that the initiation of the August 14th power outage resulted from the coincidence on that afternoon of several events, including: 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 14th power outage and that it does not adequately address the underlying causes of the outage. FirstEnergy remains convinced that the outage cannot be explained by events on any one utility's system. 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 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 14th power outage, 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 Reliability Initiatives above). 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 June 30, 2004 for any expenditures in excess of those actually incurred through that date. Legal Matters FirstEnergy's Ohio utility subsidiaries were named as respondents in two regulatory proceedings initiated at the PUCO in response to complaints alleging failure to provide reasonable and adequate service stemming primarily from the August 14th power outage. 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 them. In particular, if FirstEnergy were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on its financial condition and results of operations. 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 outage. All three cases were dismissed for lack of jurisdiction. One case was refiled at the PUCO and the other two have been appealed. Various lawsuits, claims, including claims for asbestos exposure, and proceedings related to OE's normal business operations are pending against OE, the most significant of which are described above. Critical Accounting Policies ---------------------------- OE prepares its consolidated financial statements in accordance with GAAP. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. All of the OE Companies' assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. The OE Companies' more significant accounting policies are described below. 73 Regulatory Accounting The OE Companies are subject to regulation that sets the prices (rates) they are permitted to charge their customers based on costs that the regulatory agencies determine the OE Companies are permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. OE regularly reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. Revenue Recognition The OE Companies follow the accrual method of accounting for revenues, recognizing revenue for electricity that has been delivered to customers but not yet billed through the end of the accounting period. The determination of electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimated and a corresponding accrual for unbilled revenues is recognized. The determination of unbilled revenues requires management to make estimates regarding electricity available for retail load, transmission and distribution line losses, consumption by customer class and electricity provided by alternative suppliers. Pension and Other Postretirement Benefits Accounting FirstEnergy's pension and post-retirement benefit obligations are allocated to its subsidiaries employing the plan participants. Employee benefits related to construction projects are capitalized. OE's reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions to the plans, and earnings on plan assets. Such factors may be further affected by business combinations (such as FirstEnergy's merger with GPU in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs are also affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. In accordance with SFAS 87 and SFAS 106, changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. FirstEnergy reduced its assumed discount rate as of December 31, 2003 to 6.25% from 6.75% used as of December 31, 2002. FirstEnergy's assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. In 2003 and 2002, plan assets actually earned 24.0% and (11.3)%, respectively. FirstEnergy's pension costs in 2003 and the first half of 2004 were computed assuming a 9.0% rate of return on plan assets based upon projections of future returns and its pension trust investment allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash. Based on pension assumptions and pension plan assets as of December 31, 2003, FirstEnergy will not be required to fund its pension plans in 2004. Health care cost trends have significantly increased and will affect future OPEB costs. The 2004 and 2003 composite health care trend rate assumptions are approximately 10%-12% gradually decreasing to 5% in later years. In determining its trend rate assumptions, FirstEnergy included the specific provisions of its health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in its health care plans, and projections of future medical trend rates. Ohio Transition Cost Amortization In connection with FirstEnergy's initial transition plan, the PUCO determined allowable transition costs based on amounts recorded on OE's regulatory books. These costs exceeded those deferred or capitalized on OE's 74 balance sheet prepared under GAAP since they included certain costs which have not yet been incurred. OE uses an effective interest method for amortizing its transition costs, often referred to as a "mortgage-style" amortization. The interest rate under this method is equal to the rate of return authorized by the PUCO in the Rate Stabilization Plan for OE. In computing the transition cost amortization, OE includes only the portion of the transition revenues associated with transition costs included on the balance sheet prepared under GAAP. Revenues collected for the off balance sheet costs and the return associated with these costs are recognized as income when received. Long-Lived Assets In accordance with SFAS 144, the OE Companies periodically evaluate their long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset might not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment has occurred, the OE Companies recognize a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). The calculation of future cash flows is based on assumptions, estimates and judgment about future events. The aggregate amount of cash flows determines whether an impairment is indicated. The timing of the cash flows is critical in determining the amount of the impairment. Nuclear Decommissioning In accordance with SFAS 143, the OE Companies recognize an ARO for the future decommissioning of their nuclear power plants. The ARO liability represents an estimate of the fair value of the OE Companies' current obligation related to nuclear decommissioning and the retirement of other assets. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. The OE Companies used an expected cash flow approach (as discussed in FCON 7) to measure the fair value of the nuclear decommissioning ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. The scenarios consider settlement of the ARO at the expiration of the nuclear power plants' current license and settlement based on an extended license term. New Accounting Standards And Interpretations -------------------------------------------- EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary and Its Application to Certain Investments" On March 31, 2004, the FASB ratified the consensus reached by the EITF 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 are to be applied to other-than-temporary impairment evaluations in reporting periods beginning after June 15, 2004. OE has available-for-sale securities with unrealized losses of approximately $1.8 million as of June 30, 2004 that will be evaluated in accordance with EITF 03-1 in the third quarter of 2004. FSP 106-2, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003" Issued May 2004, FSP 106-2 provides guidance on the 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. See Note 4 for a discussion of the effect of the federal subsidy provided under the Medicare Act on the consolidated financial statements. FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities" In December 2003, the FASB issued a revised interpretation of Accounting Research Bulletin No. 51, "Consolidated Financial Statements", 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, OE 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 OE's consolidated financial statements. See Note 2 - Consolidation for a discussion of variable interest entities. 75 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (Unaudited)

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited)

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Stockholders and Board of Directors of The Cleveland Electric Illuminating Company: We have reviewed the accompanying consolidated balance sheet of The Cleveland Illuminating Electric Company and its subsidiaries as of June 30, 2004, and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and six-month periods ended June 30, 2004 and 2003. These interim financial statements are the responsibility of the Company's management. We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America. We previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet and the consolidated statement of capitalization as of December 31, 2003, and the related consolidated statements of income, common stockholder's equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company's change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 1(F) to those consolidated financial statements and the Company's change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 7 to those consolidated financial statements) dated February 25, 2004 we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2003, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived. PricewaterhouseCoopers LLP Cleveland, Ohio August 6, 2004 79 THE CLEVELAND ELECTRIC ILLUMINATING COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION CEI is a wholly owned, electric utility subsidiary of FirstEnergy. CEI conducts business in portions of Ohio, providing regulated electric distribution services. CEI also provides generation services to those customers electing to retain them as their power supplier. CEI provides power directly to some alternative energy suppliers under CEI's transition plan. CEI has unbundled the price of electricity into its component elements - including generation, transmission, distribution and transition charges. Power supply requirements of CEI are provided by FES -- an affiliated company. Results Of Operations --------------------- Earnings on common stock in the second quarter of 2004 increased to $48 million from $7 million in the second quarter of 2003. For the first six months of 2004, earnings on common stock increased to $95 million from $66 million in the same period of 2003. Earnings on common stock in the first six months of 2003 included an after-tax credit of $42 million from the cumulative effect of an accounting change due to the adoption of SFAS 143. Income before the cumulative effect was $25 million in the first half of 2003. Increased earnings in both 2004 periods resulted principally from higher operating revenues and lower nuclear operating costs partially offset by higher other operating costs compared to 2003. Revenues for both periods were higher due to significant increases in wholesale sales. Lower nuclear operating costs in the second quarter and the first six months of 2004, compared with the same periods of 2003, were primarily due to the reduction in incremental costs associated with the Davis-Besse extended outage and unplanned work performed during the Perry Plant's nuclear refueling outage in the second quarter of 2003. Operating revenues increased by $29 million or 7.0% in the second quarter of 2004 from the same period of 2003. Higher revenues resulted principally from a $43 million (65.3%) increase in wholesale sales (primarily to FES) due to increased nuclear generation available for sale which was partially offset by a 2.3% decrease in retail generation sales that reduced generation sales revenue by $4 million. In the first six months of 2004, operating revenues increased by $36 million (4.3%) primarily as a result of a $57 million increase in wholesale sales revenues (primarily to FES) due to increased available nuclear generation in the first half of 2004. The increase in wholesale sales was partially offset by a 3.6% decrease in retail generation sales, which resulted in lower revenues of $10 million. The reduction in retail generation sales resulted from an increase in electric generation services provided by alternative suppliers as a percent of total sales deliveries in CEI's franchise area by 1.2 percentage points and 2.9 percentage points in the second quarter and the first half of 2004, respectively, as compared to the same periods in 2003. Distribution deliveries were nearly unchanged in the second quarter of 2004 and increased 1.2% in the first six months of 2004 compared to the corresponding periods of 2003. Commercial and industrial distribution deliveries increased 0.6% and 1.4%, respectively, but were offset by a 4.7% reduction in deliveries to residential customers resulting from moderate temperatures affecting air conditioning demand in the second quarter of 2004. Lower revenues of $3 million from electricity throughput in that period were due to lower unit costs. In the first half of 2004, a 2.9% increase in distribution deliveries to industrial customers reflected an improving economy; however, revenues from electricity throughput decreased $5 million due to lower unit prices, which offset the effect of higher volume. Under the Ohio transition plan, CEI provides incentives to customers to encourage switching to alternative energy providers - $7 million of additional credits in the second quarter and $4 million of additional credits in the first six months of 2004 compared with the corresponding periods of 2003. The lower credit amount in the first six months of 2004 was due to decreased credits in the first quarter of 2004 resulting from lower unit prices of the shopping incentives offsetting increased shopping levels in that period. These revenue reductions are deferred for future recovery under the transition plan and do not materially affect current period earnings. Changes in electric generation sales and distribution deliveries in the second quarter and first six months of 2004 from the corresponding periods of 2003 are summarized in the following table: 80 Changes in Kilowatt-hour Sales Three Months Six Months -------------------------------------------------------------------- Increase (Decrease) Electric Generation: Retail................................ (2.3)% (3.6)% Wholesale............................. 66.3% 35.8% ------------------------------------------------------------------ Total Electric Generation Sales......... 29.5% 15.0% ================================================================== Distribution Deliveries: Residential........................... (4.7)% (1.3)% Commercial............................ 0.6% 0.8% Industrial............................ 1.4% 2.9% ------------------------------------------------------------------ Total Distribution Deliveries (0.3)% 1.2% ================================================================== Operating Expenses and Taxes Total operating expenses and taxes decreased by $4 million in the second quarter and $17 million in the first six months of 2004 from the same periods of 2003. The following table presents changes from the prior year by expense category. Operating Expenses and Taxes - Changes Three Months Six Months --------------------------------------------------------------------------- Increase (Decrease) (In millions) Fuel.......................................... $ 9 $ 12 Purchased power............................... 5 4 Nuclear operating costs....................... (44) (72) Other operating costs......................... 9 16 -------------------------------------------------------------------------- Total operation and maintenance expenses.... (21) (40) Provision for depreciation and amortization... (3) 7 General taxes................................. (3) (4) Income taxes.................................. 23 20 -------------------------------------------------------------------------- Total operating expenses and taxes.......... $ (4) $ (17) ========================================================================== Higher fuel costs in the second quarter and first six months of 2004, compared with the same periods of 2003, resulted from increased fossil and nuclear generation. Higher purchased power costs reflect higher unit costs, partially offset by lower kilowatt-hours purchased. Reductions in nuclear operating costs for both periods were due to the reduction in incremental costs associated with the Davis-Besse outage and unplanned work performed during the Perry nuclear plant's 56-day refueling outage (44.85% ownership) in the second quarter of 2003. The increase in other operating costs in the second quarter and first six months of 2004, compared to the same periods of 2003, resulted primarily from higher vegetation management costs. The decrease in depreciation and amortization charges in the second quarter of 2004, compared with the first quarter of 2003, was primarily due to higher shopping incentive deferrals ($6 million) and shopping incentive carrying charges (see Regulatory Matters) in the second quarter of 2004 ($7 million), partially offset by increased amortization of regulatory assets ($10 million). The increase in depreciation and amortization charges in the first six months of 2004, compared with the first six months of 2003 was primarily due to increased amortization of regulatory assets ($16 million), partially offset by higher shopping incentive deferrals ($4 million) and the shopping incentive carrying charges ($7 million). General taxes decreased in the second quarter and first six months of 2004, compared to the same period last year, primarily due to reduced property taxes (including a $2 million refund received on a real estate valuation settlement). Other Income Other income increased by $5 million in the second quarter and $12 million in the first six months of 2004, compared to the same period in 2003, principally due to interest income from Shippingport which was consolidated into CEI as of December 31, 2003. Net Interest Charges Net interest charges continued to trend lower, decreasing by $3 million in the second quarter and $10 million in the first six months of 2004 from the same periods last year, reflecting redemptions and refinancings since the end of the second quarter of 2003. CEI's long-term debt redemptions of $8 million during the first six months of 2004 are expected to result in annualized savings of approximately $700,000. Cumulative Effect of Accounting Change Upon adoption of SFAS 143 in the first quarter of 2003, CEI recorded an after-tax credit to net income of $42 million. The cumulative effect adjustment for unrecognized depreciation, accretion offset by the reduction in 81 the existing decommissioning liabilities and ceasing the accounting practice of depreciating non-regulated generation assets using a cost of removal component was a $73 million increase to income, or $42 million net of income taxes. Preferred Stock Dividend Requirements Preferred stock dividend requirements increased $2 million in the first six months of 2004, compared to the same period last year, due to an adjustment that reduced costs in the first quarter of 2003. Capital Resources And Liquidity ------------------------------- CEI's cash requirements in 2004 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing its net debt and preferred stock outstanding. Available borrowing capacity under short-term credit facilities will be used to manage working capital requirements. Over the next two years, CEI expects to meet its contractual obligations with cash from operations. Thereafter, CEI expects to use a combination of cash from operations and funds from the capital markets. Changes in Cash Position As of June 30, 2004, CEI had $200,000 of cash and cash equivalents, compared with $25 million as of December 31, 2003. The major sources for changes in these balances are summarized below. Cash Flows From Operating Activities Cash provided by operating activities during the second quarter and first six months of 2004, compared with the corresponding periods in 2003 were as follows: Three Months Ended Six Months Ended June 30, June 30, ------------------- ----------------- Operating Cash Flows 2004 2003 2004 2003 ------------------------------------------------------------------------ (In millions) Cash earnings (1)....... $ 107 $ 40 $179 $ 72 Working capital and other (106) 84 (18) 57 ------------------------------------------------------------------------ Total ........... $ 1 $124 $161 $129 ======================================================================== (1) Includes net income, depreciation and amortization, deferred operating lease costs deferred income taxes, investment tax credits and major noncash charges. Net cash provided from operating activities decreased $123 million in the second quarter of 2004 from the second quarter of 2003 as a result of a $190 million decrease from changes in working capital and other, partially offset by a $67 million increase in cash earnings. The largest factor contributing to the change in working capital was a decrease in accounts payable. Net cash provided from operating activities increased $32 million in the first six months of 2004 compared to the same period last year as a result of a $107 million increase in cash earnings, partially offset by a $75 million reduction from changes in working capital - principally a decrease in accounts payable. The increase in cash earnings reflects the favorable impact of reduced nuclear operating costs. Cash Flows From Financing Activities Net cash provided from financing activities increased $95 million in the second quarter of 2004 from the second quarter of 2003. The increase in funds provided from financing activities resulted from a decrease in net redemptions of debt of $101 million and an $84 million net increase in short-term borrowings, partially offset by a $90 million increase in common stock dividends to FirstEnergy. Net cash used for financing activities increased $57 million in the first six months of 2004 from the same period last year. The increase was a result of $145 million increase in common stock dividends to FirstEnergy partially offset by an $88 million reduction in net redemptions of debt. CEI had about $0.7 million of cash and temporary investments (which include short-term notes receivable from associated companies) and approximately $117 million of short-term indebtedness as of June 30, 2004. CEI had the capability to issue $1.1 billion of additional first mortgage bonds on the basis of property additions and retired bonds. CEI has no restrictions on the issuance of preferred stock. CEI has the ability to borrow from its regulated affiliates and FirstEnergy to meet its short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving a loan under the money pool 82 agreements must repay the principal amount, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the second quarter of 2004 was 1.39%. On June 15, 2004, $27.7 million Ohio Water Development Authority Series 1999-A pollution control revenue refunding bonds were remarketed and converted to a weekly interest rate mode, and a letter of credit in support of principal and interest payments on the bonds was issued. CEI's access to capital markets and costs of financing are dependent on the ratings of its securities and that of FirstEnergy. On April 28, 2004, Moody's published a Liquidity Risk Assessment of FirstEnergy Corp. stating that FirstEnergy had "adequate liquidity." Moody's noted that FirstEnergy's committed credit facilities at the holding company level provided a substantial source of liquidity. Moody's also noted that, in the past year, FirstEnergy had lengthened the average maturity of its bank facilities and had made reductions to its total consolidated debt level. On April 30, 2004, Moody's published a Credit Opinion of FirstEnergy Corp. Moody's cited the stable and predictable cash flows of FirstEnergy's core utility operations, management's focus on increasing financial flexibility through debt reduction and divestiture of non-core assets, FirstEnergy's integrated regional strategy, and strong liquidity as credit strengths. Moody's noted the substantial debt burden associated with the GPU merger, fully competitive generating markets, and modest growth in markets served as credit challenges for FirstEnergy. Moody's also noted that a "track record of improving financial condition, especially a track record of debt reduction, could cause the ratings to go up" and that the opposite development could cause the ratings to go down. On June 14, 2004, S&P stated that the June 9, 2004 PUCO decision on FirstEnergy's Rate Stabilization Plan did not affect the ratings or the outlook on FirstEnergy. Cash Flows From Investing Activities In the second quarter and first six months of 2004, net cash used for investing activities decreased $29 million and $31 million, respectively, from the corresponding periods of 2003. The decrease in funds used for investing activities primarily reflected lower capital expenditures and increased loan payments from associated companies. During the second half of 2004, capital requirements for property additions are expected to be about $77 million, including $26 million for nuclear fuel. CEI has additional requirements of approximately $281 million to meet sinking fund requirements for preferred stock and maturing long-term debt during the remainder of 2004. Off-Balance Sheet Arrangements ------------------------------ Obligations not included on CEI's Consolidated Balance Sheet primarily consist of sale and leaseback arrangements involving the Bruce Mansfield Plant. As of June 30, 2004, the present value of these sale and leaseback operating lease commitments, net of trust investments, total $111 million. CEI sells substantially all of its retail customer receivables to CFC, a wholly owned subsidiary of CEI. CFC subsequently transfers the receivables to a trust (a "qualified special purpose entity" under SFAS 140) under an asset-backed securitization agreement. This arrangement provided $117 million of off-balance sheet financing as of June 30, 2004. As of June 30, 2004, off-balance sheet arrangements include certain statutory business trusts created by CEI to issue trust preferred securities in the amount of $100 million. These trusts were included in the consolidated financial statements of FirstEnergy prior to adoption of FIN 46R effective December 31, 2003, but have subsequently been deconsolidated under FIN 46R (see Note 2 - Consolidation). The deconsolidation under FIN 46R did not result in any change in outstanding debt. Equity Price Risk ----------------- Included in CEI's nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $210 million and $188 million as of June 30, 2004 and December 31, 2003, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $21 million reduction in fair value as of June 30, 2004. Outlook ------- Beginning in 2001, CEI's customers were able to select alternative energy suppliers. CEI continues to deliver power to residential homes and businesses through its existing distribution system, which remains regulated. 83 Customer rates were restructured into separate components to support customer choice. CEI has a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier subject to certain limits. Adopting new approaches to regulation and experiencing new forms of competition have created new uncertainties. Regulatory Matters In 2001, Ohio customer rates were restructured to establish separate charges for transmission, distribution, transition cost recovery and a generation-related component. When one of CEI's customers elects to obtain power from an alternative supplier, CEI reduces the customer's bill with a "generation shopping credit," based on the regulated generation component (plus an incentive), and the customer receives a generation charge from the alternative supplier. Under the recently approved Rate Stabilization Plan, CEI has continuing PLR responsibility to its franchise customers through December 31, 2008. As part of CEI's transition plan, it is obligated to supply electricity to customers who do not choose an alternative supplier. CEI is also required to provide 400 MW of low cost supply to unaffiliated alternative suppliers who serve customers within its service area. CEI's competitive retail sales affiliate, FES, acts as an alternate supplier for a portion of the load in its franchise area. On October 21, 2003, the Ohio EUOC 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: o A competitive auction, which would establish a price for generation that customers would be charged during the period covered by the auction, or o A Rate Stabilization Plan, which would extend current generation prices through 2008, ensuring adequate generation supply at stable prices, and continuing CEI's support of energy efficiency and economic development efforts. Under that proposal, CEI requested: o Extension of the transition cost amortization period for CEI from 2008 to 2009; o Deferral of interest costs on the accumulated shopping incentives and other cost deferrals as new regulatory assets; and o 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, CEI 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 CEI's revised Rate Stabilization Plan application. Among the major modifications were the following: o Limiting the ability of CEI to request adjustments in generation charges during 2006 through 2008 for increases in taxes; o Expanding the availability of market support generation; o Revising the kilowatt-hour target level and the time period for recovering regulatory transition charges; o Establishing a 3-year competitive bid process for generation; o Establishing the 2005 generation credit for shopping customers, which would be extended as a cap through 2008; and o Denying the ability to defer costs for future recovery of distribution reliability improvement expenditures. 84 On June 18, 2004, the CEI 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: o Expanding CEI's 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; o Approving the revised kilowatt-hour target level and time period for recovery of regulatory transition costs as presented by CEI in its rehearing application; o Retaining the requirement for expanded availability of market support generation, but adopting CEI's alternative approach that conditions expanded availability on higher pricing and eliminating the requirement to reduce the interest deferral for certain affected rate schedules; o Revising the calculation of the shopping credit cap for certain commercial and small industrial rate schedules; and o Relaxing the notice requirement for availability of enhanced shopping credits in a number of instances. On August 5, 2004, CEI accepted the Rate Stabilization Plan as modified and approved by the PUCO on August 4, 2004. CEI retains 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, CEI 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 mid-2009 for CEI) and the deferral of interest costs on the accumulated deferred shopping incentives. Regulatory assets are costs which have been authorized by the PUCO and the FERC for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. CEI's regulatory assets as of June 30, 2004 and December 2003 were $1.0 billion and $1.1 billion, respectively. All of CEI's regulatory assets are expected to continue to be recovered under the provisions of the transition plan. Reliability Initiatives On October 15, 2003, NERC issued a letter to all NERC control areas and reliability coordinators requesting that a review of various reliability practices be undertaken within 60 days. The Company issued its response on December 15, 2003, confirming that its review had taken place and noted that it was undertaking various enhancements to current practices. On February 10, 2004, NERC issued its Recommended Actions to Prevent and Mitigate the Impacts of Future Cascading Blackouts. Approximately 20 of the recommendations were directed at the FirstEnergy companies and broadly focused on initiatives that were recommended for completion by June 30, 2004. These initiatives principally related to: changes in voltage criteria and reactive resources management; operational preparedness and action plans; emergency response capabilities; and preparedness and operating center training. FirstEnergy presented a detailed implementation plan to NERC, which the NERC Board of Trustees subsequently endorsed on May 7, 2004. The various initiatives required by NERC to be completed by June 30, 2004 have been certified as complete to NERC (on June 30, 2004), with one minor exception related to reactive testing of certain generators expected to be completed later this year. An independent NERC verification team conducted an on-site review of the completion status, reporting on July 14, 2004, that FirstEnergy had implemented the policies, procedures and actions that were recommended to be completed by June 30, 2004, with the exception noted by FirstEnergy. Implementation of the recommendations has not required incremental material investment or upgrades to existing equipment. On February 26 and 27, 2004, CEI participated in a NERC Control Area Readiness Audit. This audit, part of an announced program by NERC to review control area operations throughout much of the United States during 2004, was an independent review to identify areas recommended for reliability improvement. The final audit report was completed on May 6, 2004. The report identified positive observations and included various recommendations for reliability improvement. FirstEnergy implemented the audit results and recommendations relating to summer 2004 and 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 finalized later this year. Implementation of the recommendations has not required incremental material investment or upgrades to existing equipment. 85 On March 1, 2004, CEI filed, in accordance with a November 25, 2003 order from the PUCO, its 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 5, 2004, the U.S. - Canada Power System Outage Task Force issued a Final Report on the August 14, 2003 power outage. 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 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 recommendations on June 30, 2004. Implementation of the recommendations has not required incremental material investment or upgrades to existing equipment. 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 summer 2004 and 2009. FirstEnergy is continuing to review the results of that study related to 2009 and completed the implementation of recommendations relating to 2004 by June 30, 2004. Based on its review thus far, FirstEnergy believes that the study does not recommend any incremental material investment or upgrades to existing equipment. FirstEnergy notes, however, that 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. 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 thereafter assembled an independent verification team to confirm implementation of NERC Recommended Actions to Prevent and Mitigate the Impacts of Future Cascading Blackouts required to be completed by June 30, 2004, as well as NERC recommendations contained in the Control Area Readiness Audit Report required to be completed by summer 2004, and recommendations in the Joint U.S. Canada Power System Outage Task Force Report directed toward FirstEnergy and required to be completed by June 30, 2004. The NERC 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. Environmental Matters Various federal, state and local authorities regulate CEI with regard to air and water quality and other environmental matters. The effects of compliance on CEI with regard to environmental matters could have a material adverse effect on its earnings and competitive position. These environmental regulations affect CEI'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, CEI 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. CEI is 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. CEI cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. CEI believes it is 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. NOx 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 NOx reductions from CEI's Ohio and Pennsylvania facilities. The EPA's NOx Transport Rule imposes uniform reductions of NOx emissions (an approximate 85% reduction in utility plant NOx 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 NOx emissions are contributing significantly to ozone levels in the eastern United States. State Implementation Plans (SIP) were required to comply by May 31, 2004 with individual state NOx budgets. Pennsylvania submitted a SIP that required compliance with the state NOx budgets at CEI's Pennsylvania facilities by May 1, 2003. Ohio submitted a SIP that required compliance with the state NOx budgets at CEI's Ohio facilities by May 31, 2004. CEI believes its facilities are complying with the state NOx budgets through combustion controls and post-combustion controls, including Selective Catalytic Reduction and Selective Non-Catalytic Reduction systems, and/or using emission allowances. 86 CEI has been named as a PRP at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site be held liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheets, based on estimates of the total costs of cleanup, CEI's proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. CEI has accrued liabilities aggregating approximately $2.4 million as of June 30, 2004. CEI accrues environmental liabilities only when it can conclude that it is probable that an obligation for such costs exists and can reasonably determine the amount of such costs. Unasserted claims are reflected in CEI's determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable. Power Outage On August 14, 2003, various states and parts of southern Canada experienced a widespread power outage. That outage 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 this outage. In the final report, the Task Force concluded, among other things, that the problems leading to the outage began in FirstEnergy's Ohio service area. Specifically, the final report concludes, among other things, that the initiation of the August 14th power outage resulted from the coincidence on that afternoon of several events, including: 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 14th power outage and that it does not adequately address the underlying causes of the outage. FirstEnergy remains convinced that the outage cannot be explained by events on any one utility's system. 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 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 14th power outage, 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 Reliability Initiatives above). 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 June 30, 2004 for any expenditures in excess of those actually incurred through that date. Legal Matters Various lawsuits, claims, including claims for asbestos exposure, and proceedings related to CEI's normal business operations are pending against CEI, the most significant of which are described herein. 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. As part of its informal inquiry, which began in September 2003, the SEC's Division of Enforcement requested on June 24, 2004 that FirstEnergy voluntarily provide information and documents related to the Davis-Besse outage. FirstEnergy is complying with this request and continues to cooperate fully with this inquiry. If it were ultimately determined that FirstEnergy has legal liability or is otherwise made subject to enforcement action based on any of the above matters with respect to the Davis-Besse outage, it could have a material adverse effect on FirstEnergy's financial condition and results of operations. FirstEnergy's Ohio utility subsidiaries were named as respondents in two regulatory proceedings initiated at the PUCO in response to complaints alleging failure to provide reasonable and adequate service stemming primarily 87 from the August 14th power outage. 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 them. In particular, if FirstEnergy were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on CEI's financial condition and results of operations. 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 outage. All three cases were dismissed for lack of jurisdiction. One case was refiled at the PUCO and the other two have been appealed. Critical Accounting Policies ---------------------------- CEI prepares its consolidated financial statements in accordance with GAAP. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. All of CEI's assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. CEI's more significant accounting policies are described below. Regulatory Accounting CEI is subject to regulation that sets the prices (rates) it is permitted to charge its customers based on costs that the regulatory agencies determine CEI is permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. CEI regularly reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. Revenue Recognition CEI follows the accrual method of accounting for revenues, recognizing revenue for electricity that has been delivered to customers but not yet billed through the end of the accounting period. The determination of electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimated and a corresponding accrual for unbilled revenues is recognized. The determination of unbilled revenues requires management to make estimates regarding electricity available for retail load, transmission and distribution line losses, consumption by customer class and electricity provided by alternative suppliers. Pension and Other Postretirement Benefits Accounting FirstEnergy's pension and post-retirement benefit obligations are allocated to its subsidiaries employing the plan participants. Employee benefits related to construction projects are capitalized. CEI's reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions to the plans, and earnings on plan assets. Such factors may be further affected by business combinations (such as FirstEnergy's merger with GPU in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs are also affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. In accordance with SFAS 87 and SFAS 106, changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. FirstEnergy reduced its assumed discount rate as of December 31, 2003 to 6.25% from 6.75% used as of December 31, 2002. 88 FirstEnergy's assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. In 2003 and 2002, plan assets actually earned 24.0% and (11.3)%, respectively. FirstEnergy's pension costs in 2003 and the first half of 2004 were computed assuming a 9.0% rate of return on plan assets based upon projections of future returns and its pension trust investment allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash. Based on pension assumptions and pension plan assets as of December 31, 2003, FirstEnergy will not be required to fund its pension plans in 2004. Health care cost trends have significantly increased and will affect future OPEB costs. The 2004 and 2003 composite health care trend rate assumptions are approximately 10%-12% gradually decreasing to 5% in later years. In determining its trend rate assumptions, FirstEnergy included the specific provisions of its health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in its health care plans, and projections of future medical trend rates. Ohio Transition Cost Amortization In connection with FirstEnergy's initial transition plan, the PUCO determined allowable transition costs based on amounts recorded on CEI's regulatory books. These costs exceeded those deferred or capitalized on CEI's balance sheet prepared under GAAP since they included certain costs which have not yet been incurred or that were recognized on the regulatory financial statements (fair value purchase accounting adjustments). CEI uses an effective interest method for amortizing its transition costs, often referred to as a "mortgage-style" amortization. The interest rate under this method is equal to the rate of return authorized by the PUCO in the Rate Stabilization Plan for CEI. In computing the transition cost amortization, CEI includes only the portion of the transition revenues associated with transition costs included on the balance sheet prepared under GAAP. Revenues collected for the off balance sheet costs and the return associated with these costs are recognized as income when received. Long-Lived Assets In accordance with SFAS 144, CEI periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset might not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment has occurred, CEI recognizes a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). The calculation of future cash flows is based on assumptions, estimates and judgment about future events. The aggregate amount of cash flows determines whether an impairment is indicated. The timing of the cash flows is critical in determining the amount of the impairment. Nuclear Decommissioning In accordance with SFAS 143, CEI recognizes an ARO for the future decommissioning of its nuclear power plants. The ARO liability represents an estimate of the fair value of CEI's current obligation related to nuclear decommissioning and the retirement of other assets. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. CEI used an expected cash flow approach (as discussed in FCON 7) to measure the fair value of the nuclear decommissioning ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. The scenarios consider settlement of the ARO at the expiration of the nuclear power plants' current license and settlement based on an extended license term. Goodwill In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, CEI evaluates goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. If impairment were to be indicated, CEI would recognize a loss - calculated as the difference between the implied fair value of its goodwill and the carrying value of the goodwill. CEI's most recent annual review was completed in the third quarter of 2003, with no impairment of goodwill indicated. The forecasts used in CEI's evaluations of goodwill reflect operations consistent with its general business assumptions. Unanticipated changes in those assumptions could have a significant effect on CEI's future evaluations of goodwill. As of June 30, 2004, CEI had $1.7 billion of goodwill. 89 New Accounting Standards And Interpretations -------------------------------------------- EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary and its Application to Certain Investments" On March 31, 2004, the FASB ratified the consensus reached by the EITF 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 are to be applied to other-than-temporary impairment evaluations in reporting periods beginning after June 15, 2004. CEI does not expect the adoption of EITF 03-1 to have a material impact on its consolidated 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 the 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. See Note 4 for a discussion of the effect of the federal subsidy provided under the Medicare Act on the consolidated financial statements. FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities" In December 2003, the FASB issued a revised interpretation of Accounting Research Bulletin No. 51, "Consolidated Financial Statements", 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, CEI 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. See Note 2 - Consolidation for a discussion of variable interest entities and the impact of the FIN 46 implementation on the financial statements of CEI. 90 THE TOLEDO EDISON COMPANY CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (Unaudited)

THE TOLEDO EDISON COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited)

THE TOLEDO EDISON COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Stockholders and Board of Directors of The Toledo Edison Company: We have reviewed the accompanying consolidated balance sheet of The Toledo Edison Company and its subsidiary as of June 30, 2004, and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and six-month periods ended June 30, 2004 and 2003. These interim financial statements are the responsibility of the Company's management. We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America. As discussed in Note 2 to the consolidated interim financial statements, the Company has restated its previously issued consolidated interim financial statements for the three-month and six-month periods ended June 30, 2003. We previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet and the consolidated statement of capitalization as of December 31, 2003, and the related consolidated statements of income, common stockholder's equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company's change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 1(F) to those consolidated financial statements and the Company's change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 7 to those consolidated financial statements) dated February 25, 2004 we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2003, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived. PricewaterhouseCoopers LLP Cleveland, Ohio August 6, 2004 94 THE TOLEDO EDISON COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION TE is a wholly owned, electric utility subsidiary of FirstEnergy. TE conducts business in northwestern Ohio, providing regulated electric distribution services. TE also provides generation services to those customers electing to retain them as their power supplier. TE provides power directly to some alternative energy suppliers under TE's transition plan. TE has unbundled the price of electricity into its component elements - including generation, transmission, distribution and transition charges. Power supply requirements of TE are provided by FES -- an affiliated company. Restatements Of Previously Reported Quarterly Results ----------------------------------------------------- As discussed in Note 2 to the Consolidated Financial Statements, TE's quarterly results for the second quarter and first six months of 2003 have been restated to correct the amounts reported for operating expenses and interest charges. TE's costs which were originally recorded as operating expenses and should have been capitalized to construction were $0.6 million ($0.3 million after tax) and $1.0 million ($0.6 million after tax) in the second quarter and the first six months of 2003, respectively. In addition, TE's interest expense was overstated by $0.3 million ($0.2 million after tax) and $1.3 million ($0.7 million after tax) in the second quarter and the first six months of 2003, respectively. The impact of these adjustments was not material to TE's Consolidated Balance Sheets or Consolidated Statements of Cash Flows for any quarter of 2003. Results Of Operations --------------------- Earnings on common stock in the second quarter of 2004 increased to $19 million from a loss of $11 million in the second quarter of 2003. Earnings on common stock in the first six months of 2004 increased to $25 million from $11 million in the first six months of 2003. The results for the six-month period in 2003 included an after-tax credit of $26 million from the cumulative effect of an accounting change due to the adoption of SFAS 143. The loss before the cumulative effect was $10 million in the first half of 2003. Increased earnings in both 2004 periods resulted principally from higher operating revenues and lower nuclear operating costs compared to 2003. Operating revenues increased by $28 million, or 12.7%, in the second quarter and by $31 million, or 6.9%, in the first six months of 2004 compared to the same periods in 2003. Higher revenues resulted from additional wholesale sales to FES due to increased generation available for sale. Wholesale sales increased 96% in the second quarter and 57% in the first half of 2004 from the same periods in 2003. Higher fossil generation at the Mansfield Plant and the return to service of Davis-Besse on April 4, 2004 increased generation available for sale in the second quarter of 2004. Increased wholesale sales in the second quarter and first six months of 2004 compared to the same periods of 2003 were partially offset by lower retail generation sales. Revenues from retail generation sales in the second quarter and first six months of 2004 decreased $5 million and $8 million, respectively, as kilowatt-hour sales of electricity by alternative suppliers in TE's franchise area increased by 1.7 percentage points in the second quarter and first half of 2004. TE's retail generation sales decreased 5.4% in the second quarter and 4.7% in the first six months of 2004 compared to the corresponding periods of 2003. Distribution deliveries decreased 3.3% in the second quarter of 2004 compared to the same period last year as a reduction in residential and industrial deliveries more than offset an increase in the commercial customer sector. A $3 million decrease in revenues from electricity throughput in the second quarter of 2004 from the same quarter last year was due to reduced distribution deliveries partially offset by higher composite prices. Under the Ohio transition plan, TE provides incentives to customers to encourage switching to alternative energy providers. These revenue reductions are deferred for future recovery under the transition plan and do not materially affect current period earnings. The reduction in revenues from shopping credits was approximately $1 million less in both the second quarter and first six months of 2004 when compared with the reductions in the corresponding periods of 2003. Changes in electric generation sales and distribution deliveries in the second quarter and first six months of 2004 from the corresponding periods of 2003 are summarized in the following table: 95 Changes in Kilowatt-Hour Sales Three Months Six Months -------------------------------------------------------------------- Increase (Decrease) Electric Generation: Retail................................ (5.4)% (4.7)% Wholesale............................. 95.9% 57.0% ------------------------------------------------------------------ Total Electric Generation Sales......... 35.0% 20.1% ================================================================== Distribution Deliveries: Residential........................... (4.9)% (5.0)% Commercial............................ 2.3% (0.9)% Industrial............................ (5.3)% (2.2)% ------------------------------------------------------------------- Total Distribution Deliveries........... (3.3)% (2.5)% =================================================================== Operating Expenses and Taxes Total operating expenses and taxes decreased by $1 million in the second quarter and by $3 million in the first six months of 2004 from the same periods in 2003. The following table presents changes from the prior year by expense category. Operating Expenses and Taxes - Changes Three Months Six Months ---------------------------------------------------------------------------- Increase (Decrease) (In millions) Fuel........................................... $ 7 $ 9 Purchased power costs.......................... -- 8 Nuclear operating costs........................ (29) (52) Other operating costs.......................... 7 11 ---------------------------------------------------------------------------- Total operation and maintenance expenses..... (15) (24) Provision for depreciation and amortization.... (3) 2 General taxes.................................. (2) (3) Income taxes................................... 19 22 ---------------------------------------------------------------------------- Net decrease in operating expenses and taxes. $ (1) $ (3) ============================================================================ Higher fuel costs in the second quarter of 2004, compared with the second quarter of 2003, resulted primarily from increased nuclear generation as a result of Davis-Besse's return to full service on April 4, 2004. Higher purchased power costs in the first six months of 2004, compared to the same period last year, reflect higher unit costs, partially offset by lower kilowatt-hours purchased due to reduced retail generation demand. Lower nuclear operating costs in the second quarter and the first six months of 2004, compared to the same periods of 2003, were primarily due to the absence of incremental costs in the second quarter and lower incremental costs in the first six months of 2004 associated with the Davis-Besse Plant restoration outage. Nuclear operating costs were also lower in the second quarter of 2004 as a result of no nuclear refueling outages compared to a 56-day refueling outage at the Perry Plant (19.91% ownership) in the second quarter of 2003. The increase in other operating costs in the second quarter and first six months of 2004, compared to the same periods of 2003, was due in part to higher vegetation management costs. Depreciation and amortization decreased by $3 million in the second quarter of 2004, compared with the second quarter of 2003, primarily due to higher shopping incentive deferrals ($1 million) and the deferral of interest costs on shopping incentives ($2 million). The interest deferrals were implemented in the second quarter of 2004 (retroactive to January 1, 2004) pursuant to the Ohio Rate Stabilization Plan. The increase in depreciation and amortization charges of $2 million in the first six months of 2004, compared with the first six months of 2003, was primarily due to the increased amortization of regulatory assets ($4 million), partially offset by higher shopping incentive deferrals ($1 million) and the deferral of interest costs on accumulated deferred shopping incentives ($2 million). Other Income Other income increased by $4 million in the first six months of 2004 compared to the same period of 2003, due primarily to the absence of 2003 costs related to closing the Acme power plant in Toledo, Ohio. Net Interest Charges Net interest charges continued to trend lower, decreasing by $1 million in the second quarter of 2004 and $2 million in the first six months of 2004 from the same periods of 2003, reflecting redemptions and refinancings since June 30, 2003. TE's long-term debt redemptions of $15 million during the first six months of 2004 and its repricing of $54 million of pollution control notes in the second quarter of 2004 are expected to result in annualized savings of approximately $1 million. 96 Cumulative Effect of Accounting Change Upon adoption of SFAS 143 in the first quarter of 2003, TE recorded an after-tax credit to net income of $26 million. The cumulative effect adjustment for unrecognized depreciation, accretion offset by the reduction in the existing decommissioning liabilities and ceasing the accounting practice of depreciating non-regulated generation assets using a cost of removal component was a $44 million increase to income, or $26 million net of income taxes. Capital Resources And Liquidity ------------------------------- TE's cash requirements in 2004 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing its net debt and preferred stock outstanding. Available borrowing capacity under short-term credit facilities will be used to manage working capital requirements. Over the next two years, TE expects to meet its contractual obligations with cash from operations. Thereafter, TE expects to use a combination of cash from operations and funds from the capital markets. Changes in Cash Position As of June 30, 2004, TE had approximately $15,000 of cash and cash equivalents, compared with $2 million as of December 31, 2003. The major sources for changes in these balances are summarized below. Cash Flows From Operating Activities Cash provided by (used for) operating activities during the second quarter and first six months of 2004 and corresponding periods in 2003 were as follows: Three Months Ended Six Months Ended June 30, June 30, ------------------------------------------- Operating Cash Flows 2004 2003 2004 2003 ------------------------------------------------------------------------ (In millions) Cash earnings (1)........ $30 $(21) $75 $ 8 Working capital and other 20 37 20 (22) ------------------------------------------------------------------------ Total.................... $50 $ 16 $95 $(14) ======================================================================== (1) Includes net income, depreciation and amortization, deferred operating lease costs, deferred income taxes, investment tax credits and major noncash charges. Net cash provided from operating activities increased $34 million in the second quarter of 2004 from the second quarter of 2003 resulting from a $51 million increase in cash earnings partially offset by a $17 million decrease from changes in working capital. The increase in cash earnings was primarily due to higher operating revenues and lower nuclear operating costs. The largest factors contributing to the change in working capital were decreases in payables and other current liabilities partially offset by a decrease in receivables. Net cash provided from operating activities increased $109 million in the first six months of 2004 from the first six months of 2003 as a result of a $67 million increase in cash earnings and a $42 million increase from changes in working capital. The change in working capital reflects lower receivables. The increase from the change in working capital also included receiving $12 million in proceeds from the settlement of TE's claim against NRG, Inc. for the terminated sale of its Bay Shore Plant. Higher operating revenues and lower nuclear costs contributed to the increase in cash earnings in the first half of 2004. Cash Flows From Financing Activities Net cash used for financing activities was $26 million in the second quarter of 2004 compared to $22 million provided from financing activities in the second quarter of 2003. The change was primarily due to increased repayments on short-term borrowings. Net cash used for financing activities was $63 million in the first six months of 2004 compared to $44 million provided from financing activities in the first six months of 2003. Repayments and redemptions of debt in the first six months of 2004 exceeded proceeds from issuing new long-term debt by $59 million. In the first six months of 2003, short-term borrowings exceeded repayments of long-term debt by $49 million. As of June 30, 2004, TE had $20 million of cash and temporary investments (which include short-term notes receivable from associated companies) and $239 million of short-term indebtedness. TE is currently precluded from issuing FMB or preferred stock based upon applicable earnings coverage tests. 97 TE has the ability to borrow from its regulated affiliates and FirstEnergy to meet its short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving a loan under the money pool agreements must repay the principal amount, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the second quarter of 2004 was 1.39%. On June 1, 2004, $34.85 million Beaver County Industrial Development Authority Series 1999-A pollution control revenue refunding bonds were remarketed and converted to a weekly interest rate mode, and a letter of credit in support of principal and interest payments on the bonds was issued. On June 15, 2004, $18.8 million Ohio Water Development Authority Series 1999-A pollution control revenue refunding bonds were remarketed and converted to a weekly interest rate mode, and a letter of credit in support of principal and interest payments on the bonds was issued. TE's access to capital markets and costs of financing are dependent on the ratings of its securities and that of its holding company, FirstEnergy. The ratings outlook on all of its securities is stable. On April 28, 2004, Moody's published a Liquidity Risk Assessment of FirstEnergy Corp. stating that FirstEnergy had "adequate liquidity." Moody's noted that FirstEnergy's committed credit facilities at the holding company level provided a substantial source of liquidity. Moody's also noted that, in the past year, FirstEnergy had lengthened the average maturity of its bank facilities and had made reductions to its total consolidated debt level. On April 30, 2004, Moody's published a Credit Opinion of FirstEnergy Corp. Moody's cited the stable and predictable cash flows of FirstEnergy's core utility operations, management's focus on increasing financial flexibility via debt reduction and divestiture of non-core assets, FirstEnergy's integrated regional strategy, and strong liquidity as credit strengths. Moody's noted the substantial debt burden associated with the GPU merger, fully competitive generating markets, and modest growth in markets served as credit challenges for FirstEnergy. Moody's also noted that a "track record of improving financial condition, especially a track record of debt reduction, could cause the ratings to go up" and that the opposite development could cause the ratings to go down. On June 14, 2004, S&P stated that the June 9, 2004 PUCO decision on FirstEnergy's Rate Stabilization Plan did not affect the ratings or the outlook on FirstEnergy. Cash Flows From Investing Activities Net cash used for investing activities decreased $5 million in the second quarter and $7 million in the first six months of 2004 when compared to the same periods of 2003 and was primarily due to lower capital expenditures in both periods. During the last two quarters of 2004, capital requirements for property additions are expected to be about $27 million. TE has additional requirements of approximately $215 million to meet sinking fund requirements for preferred stock and maturing long-term debt during the remainder of 2004. The cash requirements are expected to be satisfied from internal cash and short-term borrowings. Off-Balance Sheet Arrangements ------------------------------ Obligations not included on TE's Consolidated Balance Sheet primarily consist of sale and leaseback arrangements involving the Bruce Mansfield Plant and Beaver Valley Unit 2. As of June 30, 2004, the present value of these sale and leaseback operating lease commitments, net of trust investments, total $561 million. TE sells substantially all of its retail customer receivables to CFC, a wholly owned subsidiary of CEI. CFC subsequently transfers the receivables to a trust (a "qualified special purpose entity" under SFAS 140) under an asset-backed securitization agreement. This arrangement provided $61 million of off-balance sheet financing as of June 30, 2004. Equity Price Risk ----------------- Included in TE's nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $163 million and $145 million as of June 30, 2004 and December 31, 2003, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $16 million reduction in fair value as of June 30, 2004. 98 Outlook ------- Beginning in 2001, TE's customers were able to select alternative energy suppliers. TE continues to deliver power to residential homes and businesses through its existing distribution system, which remains regulated. Customer rates were restructured into separate components to support customer choice. Under the recently approved Rate Stabilization Plan, TE has continuing PLR responsibility to its franchise customers through December 31, 2008. Adopting new approaches to regulation and experiencing new forms of competition have created new uncertainties. Regulatory Matters In 2001, Ohio customer rates were restructured to establish separate charges for transmission, distribution, transition cost recovery and a generation-related component. When one of TE's customers elects to obtain power from an alternative supplier, TE reduces the customer's bill with a "generation shopping credit," based on the regulated generation component (plus an incentive), and the customer receives a generation charge from the alternative supplier. Under the recently approved Rate Stabilization Plan, TE has continuing PLR responsibility to its franchise customers through December 31, 2008. As part of TE's transition plan, it is obligated to supply electricity to customers who do not choose an alternative supplier. TE is also required to provide 160 MW of low cost supply to unaffiliated alternative suppliers who serve customers within its service area. FES acts as an alternate supplier for a portion of the load in TE's franchise area. On October 21, 2003, the Ohio EUOC 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: o A competitive auction, which would establish a price for generation that customers would be charged during the period covered by the auction, or o A Rate Stabilization Plan, which would extend current generation prices through 2008, ensuring adequate generation supply at stable prices, and continuing TE's support of energy efficiency and economic development efforts. Under that proposal, TE requested: o Extension of the transition cost amortization period TE from mid-2007 to 2008; o Deferral of interest costs on the accumulated shopping incentives and other cost deferrals as new regulatory assets; and o 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, TE 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 TE's revised Rate Stabilization Plan application. Among the major modifications were the following: o Limiting the ability of TE to request adjustments in generation charges during 2006 through 2008 for increases in taxes; o Expanding the availability of market support generation; o Revising the kilowatt-hour target level and the time period for recovering regulatory transition charges; o Establishing a 3-year competitive bid process for generation; o Establishing the 2005 generation credit for shopping customers, which would be extended as a cap through 2008; and o Denying the ability to defer costs for future recovery of distribution reliability improvement expenditures. 99 On June 18, 2004, TE 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: o Expanding TE's 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; o Approving the revised kilowatt-hour target level and time period for recovery of regulatory transition costs as presented by TE in its rehearing application; o Retaining the requirement for expanded availability of market support generation, but adopting TE's alternative approach that conditions expanded availability on higher pricing and eliminating the requirement to reduce the interest deferral for certain affected rate schedules; o Revising the calculation of the shopping credit cap for certain commercial and small industrial rate schedules; and o Relaxing the notice requirement for availability of enhanced shopping credits in a number of instances. On August 5, 2004, TE accepted the Rate Stabilization Plan as modified and approved by the PUCO on August 4, 2004. TE retains 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, TE 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 mid-2008 for TE) and the deferral of interest costs on the accumulated deferred shopping incentives. Regulatory assets are costs which have been authorized by the PUCO and the FERC for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. TE's regulatory assets as of June 30, 2004 and December 2003 were $416 million and $459 million, respectively. All of TE's regulatory assets are expected to continue to be recovered under the provisions of the transition plan. Reliability Initiatives On October 15, 2003, NERC issued a letter to all NERC control areas and reliability coordinators requesting that a review of various reliability practices be undertaken within 60 days. The Company issued its response on December 15, 2003, confirming that its review had taken place and noted that it was undertaking various enhancements to current practices. On February 10, 2004, NERC issued its Recommended Actions to Prevent and Mitigate the Impacts of Future Cascading Blackouts. Approximately 20 of the recommendations were directed at the FirstEnergy companies and broadly focused on initiatives that were recommended for completion by June 30, 2004. These initiatives principally related to: changes in voltage criteria and reactive resources management; operational preparedness and action plans; emergency response capabilities; and preparedness and operating center training. FirstEnergy presented a detailed implementation plan to NERC, which the NERC Board of Trustees subsequently endorsed on May 7, 2004. The various initiatives required by NERC to be completed by June 30, 2004 have been certified as complete to NERC (on June 30, 2004), with one minor exception related to reactive testing of certain generators expected to be completed later this year. An independent NERC verification team conducted an on-site review of the completion status, reporting on July 14, 2004, that FirstEnergy had implemented the policies, procedures and actions that were recommended to be completed by June 30, 2004, with the exception noted by FirstEnergy. Implementation of the recommendations has not required incremental material investment or upgrades to existing equipment. On February 26 and 27, 2004, TE participated in a NERC Control Area Readiness Audit. This audit, part of an announced program by NERC to review control area operations throughout much of the United States during 2004, was an independent review to identify areas recommended for reliability improvement. The final audit report was completed on May 6, 2004. The report identified positive observations and included various recommendations for reliability improvement. FirstEnergy implemented the audit results and recommendations relating to summer 2004 and 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 finalized later this year. Implementation of the recommendations has not required incremental material investment or upgrades to existing equipment. 100 On March 1, 2004, TE filed, in accordance with a November 25, 2003 order from the PUCO, its 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 5, 2004, the U.S. - Canada Power System Outage Task Force issued a Final Report on the August 14, 2003 power outage. 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 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 recommendations on June 30, 2004. Implementation of the recommendations has not required incremental material investment or upgrades to existing equipment. 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 summer 2004 and 2009. FirstEnergy is continuing to review the results of that study related to 2009 and completed the implementation of recommendations relating to 2004 by June 30, 2004. Based on its review thus far, FirstEnergy believes that the study does not recommend any incremental material investment or upgrades to existing equipment. FirstEnergy notes, however, that 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. 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 thereafter assembled an independent verification team to confirm implementation of NERC Recommended Actions to Prevent and Mitigate the Impacts of Future Cascading Blackouts required to be completed by June 30, 2004, as well as NERC recommendations contained in the Control Area Readiness Audit Report required to be completed by summer 2004, and recommendations in the Joint U.S. Canada Power System Outage Task Force Report directed toward FirstEnergy and required to be completed by June 30, 2004. The NERC 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. Environmental Matters Various federal, state and local authorities regulate TE with regard to air and water quality and other environmental matters. The effects of compliance on TE with regard to environmental matters could have a material adverse effect on its earnings and competitive position. These environmental regulations affect TE'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, TE 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. TE is 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. TE cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. TE believes it is 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. NOx 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 NOx reductions from TE's Ohio and Pennsylvania facilities. The EPA's NOx Transport Rule imposes uniform reductions of NOx emissions (an approximate 85% reduction in utility plant NOx 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 NOx emissions are contributing significantly to ozone levels in the eastern United States. State Implementation Plans (SIP) were required to comply by May 31, 2004 with individual state NOx budgets. Pennsylvania submitted a SIP that required compliance with the state NOx budgets at TE's Pennsylvania facilities by May 1, 2003. Ohio submitted a SIP that requires compliance with the state NOx budgets at TE's Ohio facilities by May 31, 2004. TE believes its facilities are complying with the state NOx budgets through combustion controls and post-combustion controls, including Selective Catalytic Reduction and Selective Non-Catalytic Reduction systems, and/or using emission allowances. 101 TE has been named as a PRP at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site be held liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheets, based on estimates of the total costs of cleanup, TE's proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. TE has accrued liabilities aggregating approximately $0.2 million as of June 30, 2004. TE accrues environmental liabilities only when it can conclude that it is probable that an obligation for such costs exists and can reasonably determine the amount of such costs. Unasserted claims are reflected in TE's determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable. Power Outage On August 14, 2003, various states and parts of southern Canada experienced a widespread power outage. That outage 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 this outage. In the final report, the Task Force concluded, among other things, that the problems leading to the outage began in FirstEnergy's Ohio service area. Specifically, the final report concludes, among other things, that the initiation of the August 14th power outage resulted from the coincidence on that afternoon of several events, including: 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 14th power outage and that it does not adequately address the underlying causes of the outage. FirstEnergy remains convinced that the outage cannot be explained by events on any one utility's system. 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 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 14th power outage, 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 Reliability Initiatives above). 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 June 30, 2004 for any expenditures in excess of those actually incurred through that date. Legal Matters Various lawsuits, claims, including claims for asbestos exposure, and proceedings related to TE's normal business operations are pending against TE, the most significant of which are described herein. 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. As part of its informal inquiry, which began in September 2003, the SEC's Division of Enforcement requested on June 24, 2004 that FirstEnergy voluntarily provide information and documents related to the Davis-Besse outage. FirstEnergy is complying with this request and continues to cooperate fully with this inquiry. If it were ultimately determined that FirstEnergy has legal liability or is otherwise made subject to enforcement action based on any of the above matters with respect to the Davis-Besse outage, it could have a material adverse effect on FirstEnergy's financial condition and results of operations. FirstEnergy's Ohio utility subsidiaries were named as respondents in two regulatory proceedings initiated at the PUCO in response to complaints alleging failure to provide reasonable and adequate service stemming primarily 102 from the August 14th power outage. 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 them. In particular, if FirstEnergy were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on TE's financial condition and results of operations. 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 outage. All three cases were dismissed for lack of jurisdiction. One case was refiled at the PUCO and the other two have been appealed. Critical Accounting Policies ---------------------------- TE prepares its consolidated financial statements in accordance with GAAP. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. All of TE's assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. TE's more significant accounting policies are described below. Regulatory Accounting TE is subject to regulation that sets the prices (rates) it is permitted to charge its customers based on costs that the regulatory agencies determine TE is permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. TE regularly reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. Revenue Recognition TE follows the accrual method of accounting for revenues, recognizing revenue for electricity that has been delivered to customers but not yet billed through the end of the accounting period. The determination of electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimated and a corresponding accrual for unbilled revenues is recognized. The determination of unbilled revenues requires management to make estimates regarding electricity available for retail load, transmission and distribution line losses, consumption by customer class and electricity provided by alternative suppliers. Pension and Other Postretirement Benefits Accounting FirstEnergy's pension and postretirement benefit obligations are allocated to subsidiaries employing the plan participants. Employee benefits related to construction projects are capitalized. TE's reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions to the plans, and earnings on plan assets. Such factors may be further affected by business combinations (such as FirstEnergy's merger with GPU in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs are also affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. In accordance with SFAS 87 and SFAS 106, changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. FirstEnergy reduced its assumed discount rate as of December 31, 2003 to 6.25% from 6.75% used as of December 31, 2002. 103 FirstEnergy's assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. In 2003 and 2002, plan assets actually earned 24.0% and (11.3)%, respectively. FirstEnergy's pension costs in 2003 and the first half of 2004 were computed assuming a 9.0% rate of return on plan assets based upon projections of future returns and its pension trust investment allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash. Based on pension assumptions and pension plan assets as of December 31, 2003, FirstEnergy will not be required to fund its pension plans in 2004. Health care cost trends have significantly increased and will affect future OPEB costs. The 2004 and 2003 composite health care trend rate assumptions are approximately 10%-12% gradually decreasing to 5% in later years. In determining its trend rate assumptions, FirstEnergy included the specific provisions of its health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in its health care plans, and projections of future medical trend rates. Ohio Transition Cost Amortization In connection with FirstEnergy's initial transition plan, the PUCO determined allowable transition costs based on amounts recorded on TE's regulatory books. These costs exceeded those deferred or capitalized on TE's balance sheet prepared under GAAP since they included certain costs which have not yet been incurred or that were recognized on the regulatory financial statements (fair value purchase accounting adjustments). TE uses an effective interest method for amortizing its transition costs, often referred to as a "mortgage-style" amortization. The interest rate under this method is equal to the rate of return authorized by the PUCO in the Rate Stabilization Plan for TE. In computing the transition cost amortization, TE includes only the portion of the transition revenues associated with transition costs included on the balance sheet prepared under GAAP. Revenues collected for the off balance sheet costs and the return associated with these costs are recognized as income when received. Long-Lived Assets In accordance with SFAS 144, TE periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset might not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment has occurred, TE recognizes a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). The calculation of future cash flows is based on assumptions, estimates and judgment about future events. The aggregate amount of cash flows determines whether an impairment is indicated. The timing of the cash flows is critical in determining the amount of the impairment. Nuclear Decommissioning In accordance with SFAS 143, TE recognizes an ARO for the future decommissioning of its nuclear power plants. The ARO liability represents an estimate of the fair value of TE's current obligation related to nuclear decommissioning and the retirement of other assets. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. TE used an expected cash flow approach (as discussed in FCON 7) to measure the fair value of the nuclear decommissioning ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. The scenarios consider settlement of the ARO at the expiration of the nuclear power plants' current license and settlement based on an extended license term. Goodwill In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, TE evaluates goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. If impairment were to be indicated, TE would recognize a loss - calculated as the difference between the implied fair value of its goodwill and the carrying value of the goodwill. TE's most recent annual review was completed in the third quarter of 2003, with no impairment of goodwill indicated. The forecasts used in TE's evaluations of goodwill reflect operations consistent with its general business assumptions. Unanticipated changes in those assumptions could have a significant effect on TE's future evaluations of goodwill. As of June 30, 2004, TE had $505 million of goodwill. 104 New Accounting Standards And Interpretations -------------------------------------------- EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary and Its Application to Certain Investments" On March 31, 2004, the FASB ratified the consensus reached by the EITF 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 are to be applied to other-than-temporary impairment evaluations in reporting periods beginning after June 15, 2004. TE does not expect the adoption of EITF 03-1 to have a material impact on its consolidated 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. See Note 4 for a discussion of the effect of the federal subsidy provided under the Medicare Act on the consolidated financial statements. FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities" In December 2003, the FASB issued a revised interpretation of Accounting Research Bulletin No. 51, "Consolidated Financial Statements", 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, TE 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. See Note 2 - Consolidation for a discussion of variable interest entities and the impact of the FIN 46 implementation on the financial statements of TE. 105 PENNSYLVANIA POWER COMPANY CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (Unaudited)

PENNSYLVANIA POWER COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited)

PENNSYLVANIA POWER COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Stockholders and Board of Directors of Pennsylvania Power Company: We have reviewed the accompanying consolidated balance sheet of Pennsylvania Power Company and its subsidiary as of June 30, 2004, and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and six-month periods ended June 30, 2004 and 2003. These interim financial statements are the responsibility of the Company's management. We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America. We previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the balance sheet and the statement of capitalization as of December 31, 2003, and the related statements of income, common stockholder's equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company's change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 1(E) to those financial statements) dated February 25, 2004 we expressed an unqualified opinion on those financial statements. In our opinion, the information set forth in the accompanying balance sheet as of December 31, 2003, is fairly stated in all material respects in relation to the balance sheet from which it has been derived. PricewaterhouseCoopers LLP Cleveland, Ohio August 6, 2004 109 PENNSYLVANIA POWER COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Penn is a wholly owned, electric utility subsidiary of OE. Penn conducts business in western Pennsylvania, providing regulated electric distribution services. Penn also provides generation services to those customers electing to retain it as their power supplier. Penn provides power directly to wholesale customers under previously negotiated contracts. Penn has unbundled the price of electricity into its component elements - including generation, transmission, distribution and transition charges. Its power supply requirements are provided by FES - an affiliated company. Penn's wholly owned subsidiary, Penn Power Funding LLC, began operations on March 30, 2004. Results of Operations --------------------- Earnings on common stock in the second quarter of 2004 increased to $17 million from $3 million in the second quarter of 2003. In the first six months of 2004, earnings on common stock increased to $36 million from $7 million in the same period of 2003. Earnings in the first half of 2003 included an after-tax credit of $11 million from the cumulative effect of an accounting change due to the adoption of SFAS 143. The loss before the cumulative effect was $1 million for the first six months of 2003. Improved results in both periods of 2004 resulted from higher operating revenues, lower nuclear operating costs and reduced net interest charges. Operating revenues increased $18 million, or 15.5%, in the second quarter and $32 million, or 13.2%, in the first six months of 2004 compared with the same periods in 2003. These increases reflect higher sales revenues of $19 million and $33 million in both periods of 2004 primarily resulting from increased wholesale revenues of $13 million and $25 million, respectively, due to increased nuclear generation available for sale to FES. Retail sales revenues increased $6 million and $8 million in the second quarter and first six months of 2004 as compared to the same periods of 2003, respectively, primarily due to a 14.5% and 8.1% increase in generation sales, respectively. Warmer weather in the second quarter of 2004 compared to the same quarter of 2003 and an improving economy were major factors for the increase in generation sales in the second quarter and first half of 2004. Distribution deliveries increased 14.5% in the second quarter and 8.1% in the first six months of 2004 compared with the same periods in 2003, with increases in all customer sectors (residential, commercial and industrial) as a result of the same factors discussed above. Higher deliveries to the steel sector in the first half of 2004 are reflected in the significant increase in kilowatt-hour sales to industrial customers. The changes in revenues from electricity throughput were relatively flat for both periods with the effect of the volume increases offset by lower composite prices. Changes in electric generation sales and distribution deliveries in the second quarter and first six months of 2004 from the same periods of 2003 are summarized in the following table: Changes in Kilowatt-Hour Sales Three Months Six Months ------------------------------------------------------------------ Increase (Decrease) Electric Generation: Retail............................. 14.5% 8.1% Wholesale.......................... 44.6% 38.1% ---------------------------------------------------------------- Total Electric Generation Sales....... 31.3% 24.3% ================================================================ Distribution Deliveries: Residential........................ 5.1% 3.8% Commercial......................... 5.2% 2.7% Industrial......................... 29.3% 17.1% ---------------------------------------------------------------- Total Distribution Deliveries......... 14.5% 8.1% ================================================================ Operating Expenses and Taxes Total operating expenses and taxes increased by $5 million in the second quarter of 2004 from the second quarter of 2003 and decreased by $3 million in the first half of 2004 from the first half of 2003. The following table presents changes from the prior year by expense category. 110 Operating Expenses and Taxes - Changes Three Months Six Months ------------------------------------------------------------------------- Increase (Decrease) (In millions) Fuel......................................... $ 2 $ 3 Purchased power costs........................ 7 12 Nuclear operating costs...................... (17) (47) Other operating costs........................ 4 3 ---------------------------------------------------------------------- Total operation and maintenance expenses.. (4) (29) Provision for depreciation and amortization.. -- -- General taxes................................ (1) (1) Income taxes................................. 10 27 ---------------------------------------------------------------------- Net change in operating expenses and taxes $ 5 $ ( 3) ======================================================================= Higher fuel costs in the second quarter and first half of 2004, compared with the same periods of 2003, resulted from increased nuclear generation. Purchased power costs were higher in both periods of 2004 reflecting increases in kilowatt-hour purchases and higher unit costs. The kilowatt-hour purchases in the second quarter and the first half of 2004 increased to meet the higher retail generation demand in both periods. Lower nuclear operating costs occurred, in large part, due to the absence in 2004 of refueling outages at Beaver Valley Unit 1 and Perry. Beaver Valley Unit 1 (65.00% ownership) and Perry (5.24% ownership) experienced refueling outages in the first and second quarters of 2003, respectively. Other operating costs increased in both periods of 2004 due in part to increased employee benefit costs. Net Interest Charges Net interest charges continued to trend lower, decreasing by approximately $2 million and $3 million in the second quarter and first half of 2004, respectively, from the same periods last year, reflecting mandatory and optional debt redemptions of $83 million since June 30, 2003. Cumulative Effect of Accounting Change Upon adoption of SFAS 143 in the first quarter of 2003, Penn recorded an after-tax credit to net income of $11 million. The cumulative adjustment for unrecognized depreciation, accretion offset by the reduction in the existing decommissioning liabilities and ceasing the accounting practice of depreciating non-regulated generation assets using a cost of removal component was an $18 million increase to income, or $11 million net of income taxes. Capital Resources and Liquidity ------------------------------- Penn's cash requirements in 2004 for operating expenses, construction expenditures, scheduled debt maturities and preferred stock redemptions are expected to be met without increasing Penn's net debt and preferred stock outstanding. Available borrowing capacity under short-term credit facilities will be used to manage working capital requirements. Over the next two years, Penn expects to meet its contractual obligations with cash from operations. Thereafter, Penn expects to use a combination of cash from operations and funds from the capital markets. Changes in Cash Position As of June 30, 2004, Penn had $38,000 of cash and cash equivalents, compared with $40,000 as of December 31, 2003. The major sources for changes in these balances are summarized below. Cash Flows From Operating Activities Cash flows provided from operating activities during the second quarter and first six months of 2004, compared with the corresponding periods in 2003, were as follows: Three Months Ended Six Months Ended June 30, June 30, ------------------------------------------- Operating Cash Flows 2004 2003 2004 2003 ------------------------------------------------------------------------ (In millions) Cash earnings (1)........ $36 $16 $74 $27 Working capital and other (2) (14) (5) 16 ------------------------------------------------------------------------ Total ............ $34 $ 2 $69 $43 ======================================================================== (1) Includes net income, depreciation and amortization, deferred income taxes, investment tax credits and major noncash charges. 111 Net cash from operating activities increased $32 million in the second quarter of 2004 compared to the same quarter of 2003 primarily due to a $20 million increase in cash earnings. During the first half of 2004, net cash from operating activities increased $26 million due to a $47 million increase in cash earnings partially offset by a $21 million decrease from changes in working capital (primarily reduced accounts payable to associated companies). The increases in cash earnings for both periods of 2004 were primarily due to the combination of higher revenues and lower nuclear operating costs. Cash Flows From Financing Activities In the second quarter of 2004, net cash used for financing activities increased to $23 million from $15 million in the same period last year. The increase resulted from the repayment of short-term borrowings and increased common stock dividends to OE. In the first half of 2004, net cash used for financing activities increased to $45 million from $28 million in the same period last year. The change resulted from increased long-term debt redemptions, partially offset by increased short-term borrowings and reduced common stock dividends to OE. Penn had $453,000 of cash and temporary investments (which include short-term notes receivable from associated companies) and $34 million of short-term indebtedness as of June 30, 2004. Penn had the capability to issue $460 million of additional FMB on the basis of property additions and retired bonds. Based upon applicable earnings coverage tests, Penn could issue up to $560 million of preferred stock (assuming no additional debt was issued) as of June 30, 2004. Penn has the ability to borrow from its regulated affiliates and FirstEnergy to meet its short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries, as well as proceeds available from bank borrowings. Available bank borrowings include $1.75 billion from FirstEnergy's and OE's revolving credit facilities. Companies receiving a loan under the money pool agreements must repay the principal amount of such a loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the second quarter of 2004 was 1.39%. In March 2004, Penn completed a receivables financing arrangement that provides borrowing capability of up to $25 million. The borrowing rate is based on bank commercial paper rates. Penn is required to pay an annual facility fee of 0.40% on the entire finance limit. The facility was undrawn as of June 30, 2004 and matures on March 29, 2005. On July 1, 2004, $14.5 million Ohio Air Quality Development Authority Series 2002-A pollution control revenue refunding bonds were remarketed in an annual interest rate mode. Penn's access to capital markets and costs of financing are dependent on the ratings of its securities and the securities of OE and FirstEnergy. The ratings outlook on all of its securities is stable. On April 28, 2004, Moody's published a Liquidity Risk Assessment of FirstEnergy Corp. stating that FirstEnergy had "adequate liquidity." Moody's noted that FirstEnergy's committed credit facilities at the holding company level provided a substantial source of liquidity. Moody's also noted that, in the past year, FirstEnergy had lengthened the average maturity of its bank facilities and had made reductions to its total consolidated debt level. On April 30, 2004, Moody's published a Credit Opinion of FirstEnergy Corp. Moody's cited the stable and predictable cash flows of FirstEnergy's core utility operations, management's focus on increasing financial flexibility via debt reduction and divestiture of non-core assets, and FirstEnergy's integrated regional strategy, and strong liquidity as credit strengths. Moody's noted the substantial debt burden associated with the GPU merger, fully competitive generating markets, and modest growth in markets served as credit challenges for FirstEnergy. Moody's also noted that a "track record of improving financial condition, especially a track record of debt reduction, could cause the ratings to go up" and that the opposite development could cause the ratings to go down. On June 14, 2004, S&P stated that the June 9, 2004 PUCO decision on FirstEnergy's Rate Stabilization Plan did not affect the ratings or the outlook on FirstEnergy. On July 22, 2004, S&P updated its analysis of U.S. utility FMB in response to changes in the industry. As a result of its revised methodology for evaluating default risk, S&P raised its FMB credit ratings for 20 U.S. utility companies including JCP&L and Penn. Penn's FMB credit rating was upgraded to BBB from BBB-. Cash Flows From Investing Activities Net cash used for investing activities totaled $11 million in the second quarter of 2004 compared to $11 million provided from investing activities in the same quarter of 2003. The $22 million change reflects an 112 increase in capital expenditures and a decrease in loan repayments from associated companies. For the first six months of 2004, net cash used for investing activities was $24 million compared to $16 million in the same period of 2003. The $8 million increase was due to reduced loan repayments from associated companies - partially offset by lower capital expenditures. During the second half of 2004, capital requirements for property additions and capital leases are expected to be about $51 million, including $19 million for nuclear fuel. Penn has additional requirements of approximately $22 million to meet sinking fund requirements for preferred stock and maturing long-term debt during the remainder of 2004. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. Equity Price Risk ----------------- Included in Penn's nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $53 million and $50 million as of June 30, 2004 and December 31, 2003, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $5 million reduction in fair value as of June 30, 2004. Outlook ------- Beginning in 1999, Penn's customers were able to select alternative energy suppliers. Penn continues to deliver power to homes and businesses through its existing distribution system, which remains regulated. The PPUC authorized Penn's rate restructuring plan, establishing separate charges for transmission, distribution, generation and stranded cost recovery, which is recovered through a CTC. Customers electing to obtain power from an alternative supplier have their bills reduced based on the regulated generation component, and the customers receive a generation charge from the alternative supplier. Penn has a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier, subject to certain limits, which is referred to as its PLR obligation. Regulatory Matters As part of Penn's transition plan it is obligated to supply electricity to customers who do not choose an alternative supplier. Penn's competitive retail sales affiliate, FES, acts as an alternate supplier for a portion of the load in its franchise area. Regulatory assets are costs which have been authorized by the PPUC and the FERC, for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. All of Penn's regulatory assets are expected to continue to be recovered under the provisions of its regulatory plan. Penn's regulatory assets totaled $8 million and $28 million as of June 30, 2004 and December 31, 2003, respectively. Reliability Initiatives On October 15, 2003, NERC issued a letter to all NERC control areas and reliability coordinators requesting that a review of various reliability practices be undertaken within 60 days. The Company issued its response on December 15, 2003, confirming that its review had taken place and noted that it was undertaking various enhancements to current practices. On February 10, 2004, NERC issued its Recommended Actions to Prevent and Mitigate the Impacts of Future Cascading Blackouts. Approximately 20 of the recommendations were directed at the FirstEnergy companies and broadly focused on initiatives that were recommended for completion by June 30, 2004. These initiatives principally related to: changes in voltage criteria and reactive resources management; operational preparedness and action plans; emergency response capabilities; and preparedness and operating center training. FirstEnergy presented a detailed implementation plan to NERC, which the NERC Board of Trustees subsequently endorsed on May 7, 2004. The various initiatives required by NERC to be completed by June 30, 2004 have been certified as complete to NERC (on June 30, 2004), with one minor exception related to reactive testing of certain generators expected to be completed later this year. An independent NERC verification team conducted an on-site review of the completion status, reporting on July 14, 2004, that FirstEnergy had implemented the policies, procedures and actions that were recommended to be completed by June 30, 2004, with the exception noted by FirstEnergy. Implementation of the recommendations has not required incremental material investment or upgrades to existing equipment. On April 5, 2004, the U.S. - Canada Power System Outage Task Force issued a Final Report on the August 14, 2003 power outage. 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 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 recommendations on June 30, 2004. Implementation of the recommendations has not required incremental material investment or upgrades to existing equipment. 113 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 thereafter assembled an independent verification team to confirm implementation of NERC Recommended Actions to Prevent and Mitigate the Impacts of Future Cascading Blackouts required to be completed by June 30, 2004, as well as NERC recommendations contained in the Control Area Readiness Audit Report required to be completed by summer 2004, and recommendations in the Joint U.S. Canada Power System Outage Task Force Report directed toward FirstEnergy and required to be completed by June 30, 2004. The NERC 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. 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 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. 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. Penn is unable to predict the outcome of this proceeding. On January 16, 2004, the PPUC initiated a formal investigation of whether Penn's "service reliability performance deteriorated to a point below the level of service reliability that existed prior to restructuring" in Pennsylvania. Discovery has commenced in the proceeding and Penn's testimony was filed May 7, 2004. On June 21, 2004, intervenors filed rebuttal testimony and Penn's surrebuttal testimony was filed on July 23, 2004. Hearings were held in early August 2004 and the ALJ has been directed to issue a Recommended Decision by September 30, 2004, in order to allow the PPUC time to issue a Final Order by the end of 2004. Penn is unable to predict the outcome of the investigation or the impact of the PPUC order. Environmental Matters Various federal, state and local authorities regulate Penn with regard to air and water quality and other environmental matters. The effects of compliance on Penn with regard to environmental matters could have a material adverse effect on its earnings and competitive position. These environmental regulations affect Penn'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, Penn 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. Penn is 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. Penn cannot predict what action the EPA may take in the future with respect to the interim enforcement policy. In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a Compliance Order 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 Penn's financial condition and results of operations. While the parties are engaged in meaningful settlement 114 discussions, management is unable to predict the ultimate outcome of this matter and no liability has been accrued as of June 30, 2004. Penn believes it is 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. NOx 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 NOx reductions from Penn's Ohio and Pennsylvania facilities. The EPA's NOx Transport Rule imposes uniform reductions of NOx emissions (an approximate 85% reduction in utility plant NOx 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 NOx emissions are contributing significantly to ozone levels in the eastern United States. State Implementation Plans (SIP) were required to comply by May 31, 2004 with individual state NOx budgets. Pennsylvania submitted a SIP that required compliance with the state NOx budgets at Penn's Pennsylvania facilities by May 1, 2003. Ohio submitted a SIP that required compliance with the state budgets at Penn's Ohio facilities by May 31, 2004. Penn believes its facilities are complying with the state NOx budgets through combustion controls and post-combustion controls, including Selective Catalytic Reduction and Selective Non-Catalytic Reduction systems, and/or using emission allowances. Power Outage On August 14, 2003, various states and parts of southern Canada experienced a widespread power outage. That outage 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 this outage. In the final report, the Task Force concluded, among other things, that the problems leading to the outage began in FirstEnergy's Ohio service area. Specifically, the final report concludes, among other things, that the initiation of the August 14th power outage resulted from the coincidence on that afternoon of several events, including: 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 14th power outage and that it does not adequately address the underlying causes of the outage. FirstEnergy remains convinced that the outage cannot be explained by events on any one utility's system. 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 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 14th power outage, 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 Reliability Initiatives above). 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 June 30, 2004 for any expenditures in excess of those actually incurred through that date. Legal Matters Various lawsuits, claims, including claims for asbestos exposure, and proceedings related to Penn's normal business operations are pending against Penn, the most significant of which are described above. Critical Accounting Policies ---------------------------- Penn prepares its consolidated financial statements in accordance with GAAP. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. All of Penn's assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. Penn's more significant accounting policies are described below. 115 Regulatory Accounting Penn is subject to regulation that sets the prices (rates) it is permitted to charge its customers based on costs that the regulatory agencies determine Penn is permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. Penn regularly reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. Revenue Recognition Penn follows the accrual method of accounting for revenues, recognizing revenue for electricity that has been delivered to customers but not yet billed through the end of the accounting period. The determination of electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimated and a corresponding accrual for unbilled revenues is recognized. The determination of unbilled revenues requires management to make estimates regarding electricity available for retail load, transmission and distribution line losses, consumption by customer class and electricity provided by alternative suppliers. Pension and Other Postretirement Benefits Accounting FirstEnergy's pension and post-retirement benefit obligations are allocated to its subsidiaries employing the plan participants. Employee benefits related to construction projects are capitalized. Penn's reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions to the plans, and earnings on plan assets. Such factors may be further affected by business combinations (such as FirstEnergy's merger with GPU in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs are also affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. In accordance with SFAS 87 and SFAS 106, changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. FirstEnergy reduced its assumed discount rate as of December 31, 2003 to 6.25% from 6.75% used as of December 31, 2002. FirstEnergy's assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. In 2003 and 2002, plan assets actually earned 24.0% and (11.3)%, respectively. FirstEnergy's pension costs in 2003 and the first half of 2004 were computed assuming a 9.0% rate of return on plan assets based upon projections of future returns and its pension trust investment allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash. Based on pension assumptions and pension plan assets as of December 31, 2003, FirstEnergy will not be required to fund its pension plans in 2004. Health care cost trends have significantly increased and will affect future OPEB costs. The 2004 and 2003 composite health care trend rate assumptions are approximately 10%-12% gradually decreasing to 5% in later years. In determining its trend rate assumptions, FirstEnergy included the specific provisions of its health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in its health care plans, and projections of future medical trend rates. Long-Lived Assets In accordance with SFAS 144, Penn periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset might not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset 116 impairment must be recognized in the financial statements. If impairment has occurred, Penn recognizes a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). The calculation of future cash flows is based on assumptions, estimates and judgment about future events. The aggregate amount of cash flows determines whether an impairment is indicated. The timing of the cash flows is critical in determining the amount of the impairment. Nuclear Decommissioning In accordance with SFAS 143, Penn recognizes an ARO for the future decommissioning of its nuclear power plants. The ARO liability represents an estimate of the fair value of Penn's current obligation related to nuclear decommissioning and the retirement of other assets. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. Penn used an expected cash flow approach (as discussed in FCON 7) to measure the fair value of the nuclear decommissioning ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. The scenarios consider settlement of the ARO at the expiration of the nuclear power plants' current license and settlement based on an extended license term. New Accounting Standards And Interpretations -------------------------------------------- EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary and Its Application to Certain Investments" On March 31, 2004, the FASB ratified the consensus reached by the EITF 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 are to be applied to other-than-temporary impairment evaluations in reporting periods beginning after June 15, 2004. Penn does not expect the adoption of EITF 03-1 to have a material impact on its consolidated 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 the 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. See Note 4 for a discussion of the effect of the federal subsidy provided under the Medicare Act on the consolidated financial statements. 117 JERSEY CENTRAL POWER & LIGHT COMPANY CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (Unaudited)

JERSEY CENTRAL POWER & LIGHT COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited)

JERSEY CENTRAL POWER & LIGHT COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Stockholders and Board of Directors of Jersey Central Power & Light Company: We have reviewed the accompanying consolidated balance sheet of Jersey Central Power & Light Company and its subsidiaries as of June 30, 2004, and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and six-month periods ended June 30, 2004 and 2003. These interim financial statements are the responsibility of the Company's management. We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America. As discussed in Note 2 to the consolidated interim financial statements, the Company has restated its previously issued consolidated interim financial statements for the three-month and six-month periods ended June 30, 2003. We previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet and the consolidated statement of capitalization as of December 31, 2003, and the related consolidated statements of income, common stockholder's equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company's change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 1(E) to those consolidated financial statements) dated February 25, 2004 we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2003, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived. PricewaterhouseCoopers LLP Cleveland, Ohio August 6, 2004 121 JERSEY CENTRAL POWER & LIGHT COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION JCP&L is a wholly owned, electric utility subsidiary of FirstEnergy. JCP&L provides regulated transmission and distribution services in northern, western and east central New Jersey. New Jersey customers are able to choose their electricity suppliers as a result of legislation which restructured the electric utility industry. JCP&L's regulatory plan required unbundling the price for electricity into its component elements - including generation, transmission, distribution and transition charges. Also under the regulatory plan, JCP&L continues to deliver power to homes and businesses through its existing distribution system and is required to maintain the PLR obligation known as BGS for customers who elect to retain JCP&L as their power supplier. Restatements Of Previously Reported Quarterly Results ----------------------------------------------------- As discussed in Note 2 to the Consolidated Financial Statements, JCP&L's quarterly results for the second quarter and first six months of 2003 have been restated to correct the amounts reported for operating expenses. JCP&L's costs, which were originally recorded as operating expenses and should have been capitalized to construction, were $3.0 million ($1.8 million after-tax) in the second quarter of 2003 and $3.2 million ($1.9 million after-tax) for the first six months of 2003. The impact of these adjustments was not material to JCP&L's Consolidated Balance Sheets or Consolidated Statements of Cash Flows for any quarter of 2003. In addition, as further discussed in Note 8 to the Consolidated Financial Statements, amounts for purchased power, other operating costs and provisions for depreciation and amortization in JCP&L's 2003 Consolidated Statements of Income were reclassified to conform with the current year presentation of generation commodity costs. These reclassifications did not change previously reported results in 2003. Results Of Operations -------------------- Earnings on common stock in the second quarter of 2004 increased to $37 million from a loss of $41 million in the same period of 2003 as a result of non-cash charges recorded in the second quarter of 2003 aggregating $159 million ($94 million after tax) due to a rate case decision disallowing recovery of those costs (see Regulatory Matters). Excluding the impact of those non-cash charges, earnings on common stock in the second quarter of 2003 were $53 million. Earnings on common stock during the first six months of 2004 were $50 million compared to $12 million for the same period of 2003. Earnings before the non-cash charges related to the rate case decision were $107 million for the first six months of 2003. Operating revenues increased $7 million or 1.3% in the second quarter of 2004, but decreased $152 million or 12.7% in the first six months of 2004, compared with the same periods in 2003. Wholesale revenues increased $17 million in the second quarter from the previous year, but declined $55 million in the first six months of 2004. JCP&L entered into long-term power purchase agreements in connection with the divestiture of its generation facilities and was selling any power in excess of its retail customer needs to the wholesale market. The long-term purchase agreements ended after the first quarter of 2003 and as a result, sales to the wholesale market decreased. A higher level of customer shopping reduced retail generation sales by 20.0% in the second quarter and 22.0% in the first six months of 2004 compared to the same periods of 2003. Lower retail generation sales were more than offset by higher unit prices reflecting the results of the BGS auction (see Regulatory Matters) and increased retail generation sales revenues by $13 million in the second quarter; retail generation sales revenues were relatively unchanged for the first half of 2004. Distribution deliveries increased by 9.1% in the second quarter and 5.0% in the first six months of 2004 compared with the same periods of 2003. The increase in deliveries in the second quarter of 2004 was based on strong demand in the residential (15.4%) and commercial (8.0%) sectors due to warmer weather, but was partially offset by a 1.0% decrease in deliveries to industrial customers. Increases in all retail sectors for the first half of 2004 reflected the second quarter increases in residential and commercial sectors, as well as higher deliveries to industrial customers (2.3%) in part due to an improving economy. The impact of the increased volume was more than offset by lower unit prices which reduced revenues from electricity throughput by $30 million for the quarter and $92 million for the first six months of 2004. In July 2003, the NJBPU announced its JCP&L base electric rate proceeding decision (see Regulatory Matters) which reduced JCP&L's distribution rates effective August 1, 2003. The decrease in distribution revenues include the impact of the lower rates - $11 million in the second quarter and $44 million in the first six months of 2004. Changes in distribution deliveries in the second quarter and first half of 2004 compared with the same periods of 2003 are summarized in the following table: 122 Changes in Kilowatt-Hour Deliveries Three Months Six Months --------------------------------------------------------------------------- Increase (Decrease) Residential........................... 15.4% 7.4% Commercial............................ 8.0% 3.9% Industrial............................ (1.0)% 2.3% -------------------------------------------------------------------------- Total Distribution Deliveries........... 9.1% 5.0% ========================================================================== Operating Expenses and Taxes Total operating expenses and taxes decreased by $70 million in the second quarter and $185 million in the first six months of 2004 compared to the same periods of 2003. The following table presents changes from the prior year by expense category. Operating Expenses and Taxes - Changes Three Months Six Months ------------------------------------------------------------------------------ Increase (Decrease) (In millions) Purchased power costs........................... $(127) $(229) Other operating costs........................... -- 16 ------------------------------------------------------------------------------ Total operation and maintenance expenses...... (127) (213) Provision for depreciation and amortization..... 2 (1) General taxes................................... 2 2 Income taxes.................................... 53 27 ------------------------------------------------------------------------------ Net decrease in operating expenses and taxes.. $ (70) $(185) ============================================================================== The changes in purchased power costs and provision for deprecation and amortization include the non-cash charges in the second quarter of 2003 for amounts disallowed in the July 2003 JCP&L rate case decision (see Regulatory Matters) - $153 million of deferred purchased power costs and $6 million charged to depreciation and amortization. Excluding the disallowed deferred energy costs, purchased power costs increased $26 million in the second quarter and decreased $76 million in the first half of 2004, compared to the corresponding periods of 2003. Kilowatt-hour purchases decreased due to lower generation sales in both the quarter and the first six months of 2004. Increased unit costs due to changes in the deferred energy and capacity costs more than offset the effect of lower kilowatt-hour purchases in the second quarter of 2004 and only partially offset the effect of reduced kilowatt-hour purchases for the first six months of 2004. The increase in other operating costs for the first six months of 2004 was primarily due to JCP&L's accelerated reliability program. Excluding the amounts disallowed in the July 2003 JCP&L rate decision, depreciation and amortization increased $8 million in the second quarter and $5 million for the first six months of 2004, reflecting an increased level of regulatory asset amortization from the rate decision partially offset by lower depreciation rates and a $5 million reduction in the second quarter of 2004 related to an interest calculation on the disallowances (see Regulatory Matters). Net Interest Charges Net interest charges decreased by $3 million in the second quarter and $6 million in the first six months of 2004 compared with the same periods of 2003, reflecting debt redemptions since June 30, 2003. Those decreases were partially offset by interest on $300 million of bonds issued in April 2004 which were used to redeem currently outstanding securities and to reduce short-term debt. Capital Resources And Liquidity ------------------------------- JCP&L's cash requirements in 2004 for operating expenses, construction expenditures and scheduled debt maturities are expected to be met without materially increasing its net debt and preferred stock outstanding. Available borrowing capacity under short-term credit facilities with affiliates will be used to manage working capital requirements. Over the next two years, JCP&L expects to meet its contractual obligations with cash from operations. Thereafter, JCP&L expects to use a combination of cash from operations and funds from the capital markets. Changes in Cash Position There was no change as of June 30, 2004 and December 31, 2003 in JCP&L's cash and cash equivalents of $0.3 million. Cash Flows From Operating Activities Cash provided from operating activities during the second quarter and first six months of 2004, compared to the corresponding periods of 2003, were as follows: 123 Three Months Ended Six Months Ended June 30, June 30, ------------------------------------------------------------------------ Operating Cash Flows 2004 2003 2004 2003 ------------------------------------------------------------------------ (In millions) Cash earnings (1)........ $ 64 $ 82 $123 $ 175 Working capital and other (11) (116) 52 (113) ------------------------------------------------------------------------ Total ............ $ 53 $ (34) $175 $ 62 ======================================================================== (1) Includes net income, depreciation and amortization, deferred income taxes, investment tax credits and major noncash charges. Net cash from operating activities increased $87 million in the second quarter of 2004 compared to the same period in 2003 due to a $105 million increase from changes in working capital, partially offset by an $18 million decrease in cash earnings. The change in working capital primarily reflects increased collections of receivables, lower prepayments and higher accrued taxes. The decrease in cash earnings is due to higher purchased power costs in the second quarter of 2004. Net cash from operating activities increased $113 million in the first half of 2004 compared to the same period in 2003 due to a $165 million increase from changes in working capital partially offset by a $52 million decrease in cash earnings. The change in working capital primarily reflects increased collections of receivables, lower prepayments and higher accrued taxes. The decrease in cash earnings is primarily due to lower operating revenues and higher purchased power costs in the first six months of 2004. Cash Flows From Financing Activities In the second quarter of 2004, net cash used for financing activities was $1 million compared to net cash provided from financing activities of $27 million in the second quarter of 2003. The change primarily reflects a $52 million increase in net debt and preferred stock redemptions partially offset by a $24 million decrease in common stock dividend payments to FirstEnergy. Net cash used in financing activities increased to $90 million in the first half of 2004 compared to $72 million in the same period of 2003. The increase resulted from a $125 million increase in net debt and preferred stock redemptions and a $108 million decrease in common stock dividend payments to FirstEnergy. JCP&L will not issue FMB other than as collateral for senior notes, since its senior note indentures prohibit (subject to certain exceptions) it from issuing any debt which is senior to the senior notes. As of June 30, 2004, JCP&L had the capability to issue $611 million of additional senior notes with FMB as collateral. Based upon applicable earnings coverage tests, JCP&L could issue a total of $470 million of preferred stock (assuming no additional debt was issued) as of June 30, 2004. On April 23, 2004, JCP&L issued $300 million of 5.625% Senior Notes due 2016. The proceeds of this transaction were used to redeem $40 million of 7.98% JCP&L Series C MTNs due 2023 and $50 million of 6.78% JCP&L Series C MTNs due 2025. The remaining proceeds will be used to fund the mandatory redemption of JCP&L's $160 million of 7.125% FMB due October 1, 2004 and to reduced short-term debt. JCP&L has the ability to borrow from its regulated affiliates and FirstEnergy to meet its short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of such a loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the second quarter of 2004 was 1.39%. On April 28, 2004, Moody's published a Liquidity Risk Assessment of FirstEnergy Corp. stating that FirstEnergy had "adequate liquidity." Moody's noted that, FirstEnergy's committed credit facilities at the holding company level provided a substantial source of liquidity. Moody's also noted, that in the past year, FirstEnergy had lengthened the average maturity of its bank facilities and had made reductions to its total consolidated debt level. On April 30, 2004, Moody's published a Credit Opinion of FirstEnergy Corp. Moody's cited the stable and predictable cash flows of FirstEnergy's core utility operations, management's focus on increasing financial flexibility through debt reduction and divestiture of non-core assets, FirstEnergy's integrated regional strategy, and strong liquidity as credit strengths. Moody's noted the substantial debt burden associated with the GPU merger, fully competitive generating markets, and modest growth in markets served as credit challenges for FirstEnergy. Moody's also noted that a "track record of improving financial condition, especially a track record of debt reduction, could cause the ratings to go up" and that the opposite development could cause the ratings to go down. 124 On June 14, 2004, S&P stated that the June 9, 2004 PUCO decision on FirstEnergy's Rate Stabilization Plan did not affect the ratings or the outlook on FirstEnergy. On July 22, 2004, S&P updated its analysis of U.S. utility FMB in response to changes in the industry. As a result of its revised methodology for evaluating default risk, S&P raised its FMB credit ratings for 20 U.S. utility companies including JCP&L. JCP&L's FMB credit rating was upgraded to BBB+ from BBB. Cash Flows From Investing Activities Net cash used for investing activities totaled $52 million and $85 million in the second quarter and first half of 2004, respectively, compared to $11 million provided from investing activities in both periods of 2003. The change in both periods was due to increased capital expenditures and decreased loan repayments from associated companies. During the second half of 2004, capital requirements for property additions are expected to be about $57 million. JCP&L has additional requirements of approximately $9 million for maturing long-term debt during the remainder of 2004. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. Market Risk Information ----------------------- JCP&L uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price fluctuations. 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. Commodity Price Risk JCP&L is exposed to market risk primarily due to fluctuations in electricity and natural gas prices. To manage the volatility relating to these exposures, it uses a variety of non-derivative and derivative instruments, including forward contracts, options and future contracts. The derivatives are used for hedging purposes. Most of JCP&L's non-hedge derivative contracts represent non-trading positions that do not qualify for hedge treatment under SFAS 133. The change in the fair value of commodity derivative contracts related to energy production during the second quarter and first six months of 2004 is summarized in the following table:

Derivatives included on the Consolidated Balance Sheet as of June 30, 2004: Non-Hedge Hedge Total ----------------------------------------------------------------------------- (In millions) Current- Other Assets............................ $-- $-- $-- Other Liabilities....................... -- -- -- Non-Current- Other Deferred Charges.................. 15 -- 15 Other Liabilities....................... -- -- -- ------------------------------------------------------------------------------ Net assets.............................. $15 $-- $15 ============================================================================== 125 The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, JCP&L relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. JCP&L uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for the valuation of derivative contracts by year are summarized in the following table:

JCP&L performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift in quoted market prices in the near term on derivative instruments would not have had a material effect on its consolidated financial position or cash flows as of June 30, 2004. Equity Price Risk Included in JCP&L's nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $74 million and $69 million as of June 30, 2004 and December 31, 2003, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $7 million reduction in fair value as of June 30, 2004. Outlook ------- Beginning in 1999, all of JCP&L's customers were able to select alternative energy suppliers. JCP&L continues to deliver power to homes and businesses through its existing distribution system, which remains regulated. To support customer choice, rates were restructured into unbundled service charges and additional non-bypassable charges to recover stranded costs. Regulatory Matters 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. In July 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 next six to twelve months. During that period, JCP&L would initiate another proceeding to request recovery of additional costs incurred to enhance system reliability. In that proceeding, the NJBPU could increase the 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 revenue decrease in the 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 charge. The MTC allowed for the recovery of $465 million in deferred energy costs over the next ten years on an interim basis, thus disallowing $153 million of the $618 million provided for in a preliminary settlement agreement between certain parties. 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 deferred energy costs and other regulatory assets. JCP&L filed a 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 NJBPU 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, (4) amortization of costs to achieve merger savings; and (5) 126 decommissioning. All other issues included in JCP&L's amended motion were denied. Oral arguments were held on August 4, 2004. Management cannot predict when a decision following the oral arguments may be announced by the NJBPU. 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 higher return on equity. The filing also requests an increase to the MTC deferred balance recovery of approximately $20 million annually. The filing also 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. 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 JCP&L's customers, without a reduction, termination or capping of the funding. Regulatory assets are costs which have been authorized by the NJBPU and the FERC for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. All of JCP&L's regulatory assets are expected to continue to be recovered under the provisions of the regulatory proceedings discussed above. JCP&L's regulatory assets were $2.3 billion and $2.6 billion as of June 30, 2004 and December 31, 2003, respectively. Environmental Matters JCP&L has been named as a PRP at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site be held liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheets, based on estimates of the total costs of cleanup, JCP&L's 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. JCP&L has accrued liabilities aggregating approximately $45.8 million as of June 30, 2004. JCP&L accrues environmental liabilities only when it can conclude that it is probable that an obligation for such costs exists and can reasonably determine the amount of such costs. Unasserted claims are reflected in JCP&L's determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable. Power Outage On August 14, 2003, various states and parts of southern Canada experienced a widespread power outage. That outage 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 this outage. In the final report, the Task Force concluded, among other things, that the problems leading to the outage began in FirstEnergy's Ohio service area. Specifically, the final report concludes, among other things, that the initiation of the August 14th power outage resulted from the coincidence on that afternoon of several events, including: 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 14th power outage and that it does not adequately address the underlying causes of the outage. FirstEnergy remains convinced that the outage cannot be explained by events on any one utility's system. 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 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 14th power outage, 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 Reliability Initiatives 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 127 the future that could require additional, material expenditures. FirstEnergy has not accrued a liability as of June 30, 2004 for any expenditures in excess of those actually incurred through that date. Reliability Initiatives On October 15, 2003, NERC issued a letter to all NERC control areas and reliability coordinators requesting that a review of various reliability practices be undertaken within 60 days. The Company issued its response on December 15, 2003, confirming that its review had taken place and noted that it was undertaking various enhancements to current practices. On February 10, 2004, NERC issued its Recommended Actions to Prevent and Mitigate the Impacts of Future Cascading Blackouts. Approximately 20 of the recommendations were directed at the FirstEnergy companies and broadly focused on initiatives that were recommended for completion by June 30, 2004. These initiatives principally related to: changes in voltage criteria and reactive resources management; operational preparedness and action plans; emergency response capabilities; and preparedness and operating center training. FirstEnergy presented a detailed implementation plan to NERC, which the NERC Board of Trustees subsequently endorsed on May 7, 2004. The various initiatives required by NERC to be completed by June 30, 2004 have been certified as complete to NERC (on June 30, 2004), with one minor exception related to reactive testing of certain generators expected to be completed later this year. An independent NERC verification team conducted an on-site review of the completion status, reporting on July 14, 2004, that FirstEnergy had implemented the policies, procedures and actions that were recommended to be completed by June 30, 2004, with the exception noted by FirstEnergy. Implementation of the recommendations has not required incremental material investment or upgrades to existing equipment. On April 5, 2004, the U.S. - Canada Power System Outage Task Force issued a Final Report on the August 14, 2003 power outage. 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 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 recommendations on June 30, 2004. Implementation of the recommendations has not required incremental material investment or upgrades to existing equipment. 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 thereafter assembled an independent verification team to confirm implementation of NERC Recommended Actions to Prevent and Mitigate the Impacts of Future Cascading Blackouts required to be completed by June 30, 2004, as well as NERC recommendations contained in the Control Area Readiness Audit Report required to be completed by summer 2004, and recommendations in the Joint U.S. Canada Power System Outage Task Force Report directed toward FirstEnergy and required to be completed by June 30, 2004. The NERC 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. On July 5, 2003, JCP&L experienced a series of 34.5 kilo-volt 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 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. JCP&L expects to spend $12.5 million implementing these actions during 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. JCP&L is awaiting the final NJBPU final order. Legal Matters Various lawsuits, claims, including claims for asbestos exposure, and proceedings related to our normal business operations are pending against us, the most significant of which are described herein. 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. 128 Since July 1999, this litigation has involved a substantial amount of legal discovery including interrogatories, request for production of documents, preservation and inspection of evidence, and depositions of the named plaintiffs and many JCP&L employees. In addition, there have been many motions filed and argued by the parties involving issues such as the primary jurisdiction and findings of the NJBPU, consumer fraud by JCP&L, strict product liability, class decertification, and the damages claimed by the plaintiffs. In January 2000, the NJ Appellate Division determined that the trial court has proper jurisdiction over this litigation. 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 July 28, 2004, both plaintiffs and JCP&L appealed the decision of the Appellate Division to the New Jersey Supreme Court. JCP&L is unable to predict the outcome of these matters and no liability has been accrued as of June 30, 2004. Critical Accounting Policies ---------------------------- JCP&L prepares its consolidated financial statements in accordance with GAAP. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. All of JCP&L's assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. JCP&L's more significant accounting policies are described below. Regulatory Accounting JCP&L is subject to regulation that sets the prices (rates) it is permitted to charge its customers based on costs that the regulatory agencies determine JCP&L is permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. JCP&L regularly reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. Derivative Accounting Determination of appropriate accounting for derivative transactions requires the involvement of management representing operations, finance and risk assessment. In order to determine the appropriate accounting for derivative transactions, the provisions of the contract need to be carefully assessed in accordance with the authoritative accounting literature and management's intended use of the derivative. New authoritative guidance continues to shape the application of derivative accounting. Management's expectations and intentions are key factors in determining the appropriate accounting for a derivative transaction and, as a result, such expectations and intentions are documented. Derivative contracts that are determined to fall within the scope of SFAS 133, as amended, must be recorded at their fair value. Active market prices are not always available to determine the fair value of the later years of a contract, requiring that various assumptions and estimates be used in their valuation. JCP&L continually monitors its derivative contracts to determine if its activities, expectations, intentions, assumptions and estimates remain valid. As part of its normal operations, JCP&L enters into commodity contracts, as well as interest rate swaps, which increase the impact of derivative accounting judgments. Revenue Recognition JCP&L follows the accrual method of accounting for revenues, recognizing revenue for electricity that has been delivered to customers but not yet billed through the end of the accounting period. The determination of electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimated and a corresponding accrual for unbilled revenues is recognized. The determination of unbilled revenues requires management to make estimates regarding electricity available for retail load, transmission and distribution line losses, consumption by customer class and electricity provided by alternative suppliers. Pension and Other Postretirement Benefits Accounting FirstEnergy's pension and post-retirement benefit obligations are allocated to its subsidiaries employing the plan participants. Employee benefits related to construction projects are capitalized. JCP&L's reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions are dependent upon numerous factors resulting from actual plan experience and certain assumptions. 129 Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions to the plans, and earnings on plan assets. Such factors may be further affected by business combinations (such as FirstEnergy's merger with GPU in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs are also affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. In accordance with SFAS 87 and SFAS 106, changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. Due to recent declines in corporate bond yields and interest rates in general, FirstEnergy reduced the assumed discount rate as of December 31, 2003 to 6.25% from 6.75% used as of December 31, 2002. FirstEnergy's assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. In 2003 and 2002, plan assets actually earned 24.0% and (11.3)%, respectively. FirstEnergy's pension costs in 2003 and the first half of 2004 were computed assuming a 9.0% rate of return on plan assets based upon projections of future returns and its pension trust investment allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash. Based on pension assumptions and pension plan assets as of December 31, 2003, FirstEnergy will not be required to fund its pension plans in 2004. Health care cost trends have significantly increased and will affect future OPEB costs. The 2004 and 2003 composite health care trend rate assumptions are approximately 10%-12% gradually decreasing to 5% in later years. In determining its trend rate assumptions, FirstEnergy included the specific provisions of its health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in its health care plans, and projections of future medical trend rates. Long-Lived Assets In accordance with SFAS 144, JCP&L periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset might not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment is indicated, JCP&L recognizes a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). The calculation of future cash flows is based on assumptions, estimates and judgment about future events. The aggregate amount of cash flows determines whether an impairment is indicated. The timing of the cash flows is critical in determining the amount of the impairment. Nuclear Decommissioning In accordance with SFAS 143, JCP&L recognizes an ARO for the future decommissioning of TMI-2. The ARO liability represents an estimate of the fair value of JCP&L's current obligation related to nuclear decommissioning. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. JCP&L used an expected cash flow approach (as discussed in FCON 7) to measure the fair value of the nuclear decommissioning ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. Goodwill In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, JCP&L evaluates goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. If impairment were to be indicated, JCP&L would recognize a loss - calculated as the difference between the implied fair value of its goodwill and 130 the carrying value of the goodwill. JCP&L's most recent annual review was completed in the third quarter of 2003, with no impairment indicated. The forecasts used in JCP&L's evaluations of goodwill reflect operations consistent with its general business assumptions. Unanticipated changes in those assumptions could have a significant effect on JCP&L's future evaluations of goodwill. In the first half of 2004, JCP&L reduced goodwill by $5 million for pre-merger interest received on an income tax refund and other tax benefits. As of June 30, 2004, JCP&L had $2 billion of goodwill. New Accounting Standards And Interpretation ------------------------------------------- EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary and Its Application to Certain Investments" On March 31, 2004, the FASB ratified the consensus reached by the EITF 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 are to be applied to other-than-temporary impairment evaluations in reporting periods beginning after June 15, 2004. JCP&L does not expect the adoption of EITF 03-1 to have a material impact on its consolidated 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 the 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. See Note 4 for a discussion of the effect of the federal subsidy provided under the Medicare Act on the consolidated financial statements. FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities" In December 2003, the FASB issued a revised interpretation of Accounting Research Bulletin No. 51, "Consolidated Financial Statements", 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, JCP&L 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 JCP&L's consolidated financial statements. For the quarter ended June 30, 2004, JCP&L evaluated its power purchase agreements and determined that it is possible that six NUG entities might be considered VIEs. JCP&L has requested but has not received the information necessary to determine whether these entities are VIEs or whether JCP&L is the primary beneficiary. As such, JCP&L applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities under FIN 46R. See Note 2 - Consolidation for a discussion of variable interest entities. 131 METROPOLITAN EDISON COMPANY CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (Unaudited)

METROPOLITAN EDISON COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited)

METROPOLITAN EDISON COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Stockholders and Board of Directors of Metropolitan Edison Company: We have reviewed the accompanying consolidated balance sheet of Metropolitan Edison Company and its subsidiaries as of June 30, 2004, and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and six-month periods ended June 30, 2004 and 2003. These interim financial statements are the responsibility of the Company's management. We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America. We previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet and the consolidated statement of capitalization as of December 31, 2003, and the related consolidated statements of income, common stockholder's equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company's change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 1(E) to those consolidated financial statements and the Company's change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 8 to those consolidated financial statements) dated February 25, 2004 we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2003, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived. PricewaterhouseCoopers LLP Cleveland, Ohio August 6, 2004 135 METROPOLITAN EDISON COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Met-Ed is a wholly owned, electric utility subsidiary of FirstEnergy. Met-Ed provides regulated transmission and distribution services in eastern Pennsylvania. Pennsylvania customers are able to choose their electricity suppliers as a result of legislation which restructured the electric utility industry. Met-Ed's regulatory plan required unbundling the price for electricity into its component elements - including generation, transmission, distribution and transition charges. Met-Ed continues to deliver power to homes and businesses through its existing distribution system and maintains PLR obligations to customers who elect to retain Met-Ed as their power supplier. Results of Operations --------------------- Net income in the second quarter of 2004 decreased to $7 million from $13 million in the second quarter of 2003. Increased purchased power costs, transmission costs and net interest charges were partially offset by increased operating revenues. During the first six months of 2004, net income decreased to $25 million from $30 million in the first six months of 2003. Net income in the first half of 2003 included an after-tax credit of $0.2 million from the cumulative effect of an accounting change due to the adoption of SFAS 143. Net income decreased in the first six months of 2004, as a result of higher purchased power and transmission costs, partially offset by higher operating revenues. The impact of these adjustments was not material to Met-Ed's Consolidated Balance Sheets or Consolidated Statements of Cash Flows for any quarter of 2003. As further discussed in Note 8 to the Consolidated Financial Statements, amounts for purchased power, other operating costs and provisions for depreciation and amortization in Met-Ed's 2003 Consolidated Statements of Income were reclassified to conform with the current year presentation of generation commodity costs. These reclassifications did not change previously reported results in 2003. Operating revenues increased by $24 million, or 11.2% in the second quarter of 2004 compared with the second quarter of 2003. Higher revenues resulted principally from increased distribution revenues of $12 million and generation sales revenues of $10 million. Revenues from electricity throughput increased as a result of higher unit prices and increased sales volume. The increase in distribution deliveries was due to higher consumption by residential and commercial customers (reflecting warmer weather in the second quarter of 2004) which was partially offset by lower deliveries to industrial customers. The increase in generation sales revenues was due to higher kilowatt-hour sales of 15.7% which were partially offset by lower unit prices. Generation sales increased primarily due to more commercial and industrial customers returning to Met-Ed as their electric service provider. Sales of electric generation by alternative suppliers as a percent of total sales delivered in Met-Ed's franchise area decreased to 9.0% in the second quarter of 2004 from 18.3% in the same period of 2003. Operating revenues increased by $34 million, or 7.3% in the first six months of 2004 compared with the first six months of 2003. Higher revenues resulted primarily from a $22 million increase from electricity throughput as a result of warmer weather in the second quarter of 2004, partially offset by lower unit prices. Retail generation kilowatt-hour sales increased by 11.5% in the first six months of 2004 resulting in an increase in operating revenues of $12 million. Sales of electric generation by alternative suppliers as a percent of total sales delivered in Met-Ed's franchise area decreased to 9.7% in the first six months in 2004 from 17.0% in the same period in 2003. The change in unit prices for generation and distribution transition revenues reflected the impact of the October 2003 PPUC order to change those rates to the previous PPUC Restructuring Settlement order levels (see Regulatory Matters). This change resulted in lower generation revenues unit prices and the corresponding increase in distribution transition revenue unit prices. Changes in distribution deliveries in the second quarter and first six months of 2004 from the same periods of 2003 are summarized in the following table: Changes in Kilowatt-Hour Sales Three Months Six Months --------------------------------------------------------------------- Increase (Decrease) Distribution Deliveries: Residential............................. 9.2% 3.4% Commercial.............................. 5.9% 4.9% Industrial.............................. (2.9)% (0.8)% ------------------------------------------------------------------- Total Distribution Deliveries............. 3.8% 2.5% =================================================================== 136 Operating Expenses and Taxes Total operating expenses and taxes increased $29 million in the second quarter and $40 million in the first six months of 2004 compared to the same periods of 2003. The following table presents changes from the prior year by expense category. Operating Expenses and Taxes - Changes Three Months Six Months ------------------------------------------------------------------------------- Increase (Decrease) (In millions) Purchased power costs............................ $24 $32 Other operating costs............................ 8 8 ---------------------------------------------------------------------------- Total operation and maintenance expenses....... 32 40 Provision for depreciation and amortization...... -- 1 General taxes.................................... 1 2 Income taxes..................................... (4) (3) ----------------------------------------------------------------------------- Net increase in operating expenses and taxes... $29 $40 ============================================================================= Purchased power costs were $24 million higher in the second quarter of 2004 from the same quarter of last year due to increased PLR kilowatt-hour purchases from FES (due to increased generation sales requirements), partially offset by reduced power from NUG sources. Other operating costs increased by $8 million in the second quarter of 2004 primarily due to higher vegetation management costs and PJM transmission costs, which were assumed by Met-Ed in the second quarter of 2004 due to a change in the PLR agreement with FES. General taxes increased by $1 million primarily due to higher gross receipt taxes in the second quarter of 2004 compared to the second quarter of 2003. Purchased power costs were $32 million higher for the first six months of 2004 compared to the same period of 2003 due to increased PLR kilowatt-hour purchases from FES (due to increased generation sales requirements), partially offset by reduced power from NUG sources. Other operating costs increased by $8 million due to higher vegetation management and transmission costs during the second quarter of 2004. Depreciation and amortization expenses were $1 million higher due to increased amortization of regulatory assets related to CTC revenue recovery. General taxes increased by $2 million due to gross receipt taxes and higher payroll taxes related to the transfer of employees to Met-Ed from GPUS. Net Interest Charges Net interest charges increased in the 2004 periods compared to the respective 2003 periods primarily due to increased interest on long-term debt, as a result of the issuance of $250 million of senior notes at the end of the first quarter of 2004. This was partially offset by the redemption of $50 million of long-term debt in the first quarter of 2004 and $100 million of unsecured subordinated debentures in the second quarter of 2004. The remaining proceeds from the senior note issuance were used for the redemption of short-term borrowings, and will be used to retire additional long-term debt in the third quarter of 2004. Net interest charges also increased due to the elimination of deferred interest for PLR energy costs in the third quarter of 2003. Capital Resources and Liquidity ------------------------------- Met-Ed expects to meet its cash requirements in 2004 for operating expenses, construction expenditures, scheduled debt maturities and optional debt redemptions without increasing its net debt and preferred stock outstanding. Over the next two years, Met-Ed expects to meet its contractual obligations with cash from operations. Thereafter, Met-Ed expects to use a combination of cash from operations and funds from the capital markets. Changes in Cash Position As of June 30, 2004, Met-Ed had $120,000 of cash and cash equivalents compared with $121,000 as of December 31, 2003. The major sources for changes in these balances are summarized below. Cash Flows From Operating Activities Cash provided from operating activities during the second quarter and first six months of 2004, compared with the corresponding periods of 2003, were as follows: 137 Three Months Ended Six Months Ended June 30, June 30, ------------------------------------------------------------------------ Operating Cash Flows 2004 2003 2004 2003 ------------------------------------------------------------------------ (In millions) Cash earnings (1)....... $19 $43 $58 $ 85 Working capital and other 30 29 (8) 20 ------------------------------------------------------------------------ Total................... $49 $72 $50 $105 ======================================================================== (1) Includes net income, depreciation and amortization, deferred costs recoverable as regulatory assets, deferred income taxes, investment tax credits and major noncash credits. Net cash provided from operating activities decreased $23 million in the second quarter of 2004 from the second quarter of 2003 primarily as a result of a $24 million decrease in cash earnings, partially offset by a $1 million increase from changes in working capital. The change in cash earnings was due to the increase in operating costs described above. The change in working capital reflects a $55 million decrease in accounts receivable and a $6 million increase in accrued interest offset by a $64 million decrease in accounts payable. Net cash provided from operating activities decreased $55 million in the first six months of 2004 from the same period of 2003 as a result of a $27 million decrease in cash earnings and a $28 million decrease from changes in working capital and other changes. Cash earnings decreased primarily due to an increase in other operating costs in the first half of 2004. The change in working capital was due to a $90 million decrease in accounts payable and an $11 million increase in prepayments and other current assets, partially offset by a $43 million decrease in accounts receivable and an increase in accrued taxes and accrued interest aggregating $13 million. Cash Flows From Financing Activities In the second quarter of 2004, net cash used in financing activities decreased to $120 million compared with $255 million in the second quarter of 2003 due to a $135 million decrease in debt reductions. In the first six months of 2004, net cash provided from financing activities was $7 million compared to $70 million of net cash used for financing activities in the first six months of 2003. The change reflected an $82 million decrease in net debt redemptions, partially offset by a $5 million increase in common stock dividends to FirstEnergy. As of June 30, 2004, Met-Ed had approximately $41 million of cash and temporary investments (which include short-term notes receivable from associated companies) and no outstanding short-term borrowings. Met-Ed will not issue FMB since its senior note indentures prohibit (subject to certain exceptions) it from issuing any debt which is senior to the senior notes. Met-Ed is not limited as to the amount of senior notes it may issue and has no restrictions on the issuance of preferred stock. Met-Ed has the ability to borrow from its regulated affiliates and FirstEnergy to meet its short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of such a loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the second quarter of 2004 was 1.39%. In March 2004, Met-Ed completed a receivables financing arrangement which provided borrowings of up to $80 million. The borrowing rate is based on bank commercial paper rates. Met-Ed is required to pay an annual facility fee of 0.30% on the entire finance limit. The facility was undrawn as of June 30, 2004 and matures on March 29, 2005. Met-Ed's access to capital markets and costs of financing are dependent on the ratings of its securities and that of FirstEnergy. The ratings outlook on all of its securities is stable. On April 28, 2004, Moody's published a Liquidity Risk Assessment of FirstEnergy Corp. stating that FirstEnergy had "adequate liquidity." Moody's noted that FirstEnergy's committed credit facilities at the holding company level provided a substantial source of liquidity. Moody's also noted that, in the past year, FirstEnergy had lengthened the average maturity of its bank facilities and had made reductions to its total consolidated debt level. On April 30, 2004, Moody's published a Credit Opinion of FirstEnergy Corp. Moody's cited the stable and predictable cash flows of FirstEnergy's core utility operations, management's focus on increasing financial flexibility via debt reduction and divestiture of non-core assets, and FirstEnergy's integrated 138 regional strategy, and strong liquidity as credit strengths. Moody's noted the substantial debt burden associated with the GPU merger, fully competitive generating markets, and modest growth in markets served as credit challenges for FirstEnergy. Moody's also noted that a "track record of improving financial condition, especially a track record of debt reduction, could cause the ratings to go up" and that the opposite development could cause the ratings to go down. On June 14, 2004, S&P stated that the June 9, 2004 PUCO decision on FirstEnergy's Rate Stabilization Plan did not affect the ratings or the outlook on FirstEnergy. Cash Flows From Investing Activities In the second quarter of 2004, net cash provided from investing activities totaled $71 million, compared to net cash used for investing activities of $29 million in the second quarter of 2003. The change resulted from a $102 million increase in loan repayments from associated companies offset in part by higher property additions. Expenditures for property additions primarily support Met-Ed's energy delivery operations. In the first six months of 2004, net cash used in investing activities totaled $57 million, compared to $50 million for the comparable period in 2003. The change was due to a $6 million increase in loans to associated companies and slightly higher property additions in the first half of 2004. During the second half of 2004, capital requirements for property additions are expected to be about $31 million. Met-Ed has additional requirements of approximately $40 million for maturing long-term debt during the remainder of 2004. These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. Market Risk Information ----------------------- Met-Ed uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price fluctuations. 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. Commodity Price Risk Met-Ed is exposed to market risk primarily due to fluctuations in electricity and natural gas prices. To manage the volatility relating to these exposures, it uses a variety of non-derivative and derivative instruments, including options and future contracts. The derivatives are used for hedging purposes. Most of Met-Ed's non-hedge derivative contracts represent non-trading positions that do not qualify for hedge treatment under SFAS 133. The change in the fair value of commodity derivative contracts related to energy production during the second quarter of 2004 is summarized in the following table:

139 Derivatives included on the Consolidated Balance Sheet as of June 30, 2004: Non-Hedge Hedge Total (In millions) Current- Other Assets...................... $ -- $ -- $ -- Other Liabilities................. -- -- -- Non-Current- Other Deferred Charges............ 30 -- 30 Other Liabilities................. ------------------------------------------------------------------- Net assets........................ $30 $ -- $30 =================================================================== The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, Met-Ed relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. Met-Ed uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for the valuation of derivative contracts by year are summarized in the following table:

(1) For the last two quarters of 2004. (2) Broker quote sheets. (3) Includes $30 million from an embedded option that is offset by a regulatory liability and does not affect earnings. Met-Ed performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift in quoted market prices in the near term on derivative instruments would not have had a material effect on its consolidated financial position or cash flows as of June 30, 2004. Equity Price Risk Included in Met-Ed's nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $123 million and $114 million as of June 30, 2004 and December 31, 2003, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $12 million reduction in fair value as of June 30, 2004. Outlook ------- Beginning in 1999, all of Met-Ed's customers were able to select alternative energy suppliers. Met-Ed continues to deliver power to homes and businesses through its existing distribution system, which remains regulated. The PPUC authorized Met-Ed's rate restructuring plan, establishing separate charges for transmission, distribution, generation and stranded cost recovery, which is recovered through a CTC. Customers electing to obtain power from an alternative supplier have their bills reduced based on the regulated generation component, and the customers receive a generation charge from the alternative supplier. Met-Ed has a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier, subject to certain limits, which is referred to as its PLR obligation. Regulatory Matters In June 2001, the PPUC approved the Settlement Stipulation with all of the major parties in the combined merger and rate proceedings which approved the FirstEnergy/GPU merger and provided PLR deferred accounting treatment for energy costs, permitting Met-Ed to defer, for future recovery, energy costs in excess of amounts reflected in its capped generation rates retroactive to January 1, 2001. This PLR deferral accounting procedure was later reversed in a February 2002 Commonwealth Court of Pennsylvania decision. The court decision affirmed the PPUC decision regarding approval of the merger, remanding the decision to the PPUC only with respect to the issue of merger savings. Met-Ed established a $103.0 million reserve in 2002 for its PLR deferred energy costs incurred prior to its acquisition by FirstEnergy, reflecting the potential adverse impact of the then pending Pennsylvania Supreme Court decision whether to review the Commonwealth Court decision. The reserve increased goodwill by an aggregate net of tax amount of $60.3 million. 140 On April 2, 2003, the PPUC remanded the issue relating to merger savings to the ALJ for hearings, directed Met-Ed 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 filed a letter with the ALJ on June 11, 2003, voiding the Stipulation in its entirety and reinstating Met-Ed'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 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 upon one day's notice. In response to that order, Met-Ed filed supplements to its tariffs to become effective October 24, 2003. On October 8, 2003, Met-Ed 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 its rights to recover all of its stranded costs. On October 9, 2003, ARIPPA (an intervenor in the proceedings) petitioned the PPUC to direct Met-Ed 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 for the NUG trust fund refund and, denying Met-Ed's other clarification requests and granting ARIPPA's petition with respect to the retroactive accounting treatment of the changes to the CTC rate/shopping credit swap. On October 22, 2003, Met-Ed filed an Objection with the Commonwealth Court asking that the Court reverse the PPUC's finding that requires Met-Ed to treat the stipulated CTC rates that were in effect from January 1, 2002 on a retroactive basis. On October 27, 2003, one Commonwealth Court judge issued an Order denying Met-Ed's Objection without explanation. Due to the vagueness of the Order, Met-Ed, on October 31, 2003, filed an Application for Clarification with the judge. Concurrent with this filing, Met-Ed, in order to preserve its 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 Objection was intended to be denied on the merits. In addition to these findings, Met-Ed, 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 purchases a portion of its 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 under its NUG contracts and other power contracts with nonaffiliated third party suppliers. This arrangement reduces Met-Ed's exposure to high wholesale power prices by providing power at a fixed price for its uncommitted PLR energy costs during the term of the agreement with FES. FES has hedged most of Met-Ed'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 is authorized to continue deferring differences between NUG contract costs and current market prices. Regulatory assets are costs which have been authorized by the PPUC and the FERC for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. All of Met-Ed's regulatory assets are expected to continue to be recovered under the provisions of its regulatory plan. Met-Ed's regulatory assets were $946 million and $1.03 billion as of June 30, 2004 and December 31, 2003, respectively. Environmental Matters Met-Ed has been named as a PRP at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site be held liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheets, based on estimates of the total costs of cleanup, Met-Ed's proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. Met-Ed has accrued liabilities aggregating approximately $29,000 as of June 30, 2004. Met-Ed accrues environmental liabilities only when it can conclude that it is probable that an obligation for such costs exists and can reasonably determine the amount of such costs. Unasserted claims are reflected in Met-Ed's determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable. 141 Power Outage On August 14, 2003, various states and parts of southern Canada experienced a widespread power outage. That outage 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 this outage. In the final report, the Task Force concluded, among other things, that the problems leading to the outage began in FirstEnergy's Ohio service area. Specifically, the final report concludes, among other things, that the initiation of the August 14th power outage resulted from the coincidence on that afternoon of several events, including: 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 14th power outage and that it does not adequately address the underlying causes of the outage. FirstEnergy remains convinced that the outage cannot be explained by events on any one utility's system. 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 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 14th power outage, 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 Reliability Initiatives 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 June 30, 2004 for any expenditures in excess of those actually incurred through that date. Reliability Initiatives On October 15, 2003, NERC issued a letter to all NERC control areas and reliability coordinators requesting that a review of various reliability practices be undertaken within 60 days. The Company issued its response on December 15, 2003, confirming that its review had taken place and noted that it was undertaking various enhancements to current practices. On February 10, 2004, NERC issued its Recommended Actions to Prevent and Mitigate the Impacts of Future Cascading Blackouts. Approximately 20 of the recommendations were directed at the FirstEnergy companies and broadly focused on initiatives that were recommended for completion by June 30, 2004. These initiatives principally related to: changes in voltage criteria and reactive resources management; operational preparedness and action plans; emergency response capabilities; and preparedness and operating center training. FirstEnergy presented a detailed implementation plan to NERC, which the NERC Board of Trustees subsequently endorsed on May 7, 2004. The various initiatives required by NERC to be completed by June 30, 2004 have been certified as complete to NERC (on June 30, 2004), with one minor exception related to reactive testing of certain generators expected to be completed later this year. An independent NERC verification team conducted an on-site review of the completion status, reporting on July 14, 2004, that FirstEnergy had implemented the policies, procedures and actions that were recommended to be completed by June 30, 2004, with the exception noted by FirstEnergy. Implementation of the recommendations has not required incremental material investment or upgrades to existing equipment. On April 5, 2004, the U.S. - Canada Power System Outage Task Force issued a Final Report on the August 14, 2003 power outage. 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 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 recommendations on June 30, 2004. Implementation of the recommendations has not required incremental material investment or upgrades to existing equipment. 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 thereafter assembled an independent verification team to confirm implementation of NERC Recommended Actions to Prevent and Mitigate the Impacts of Future Cascading Blackouts required to be completed by June 30, 2004, as well as NERC recommendations contained in the Control Area Readiness Audit Report required to be completed by summer 2004, and recommendations in the Joint U.S. Canada Power System Outage Task Force Report directed toward FirstEnergy and required to be completed by June 30, 2004. The 142 NERC 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. 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. 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 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. Met-Ed is unable to predict the outcome of this proceeding. On January 16, 2004, the PPUC initiated a formal investigation of whether Met-Ed's "service reliability performance deteriorated to a point below the level of service reliability that existed prior to restructuring" in Pennsylvania. Discovery has commenced in the proceeding and Met-Ed's testimony was filed May 7, 2004. On June 21, 2004, intervenors filed rebuttal testimony and Met-Ed's surrebuttal testimony was filed on July 23, 2004. Hearings were held in early August 2004 and the ALJ has been directed to issue a Recommended Decision by September 30, 2004, in order to allow the PPUC time to issue a Final Order by the end of 2004. Met-Ed is unable to predict the outcome of the investigation or the impact of the PPUC order. Legal Matters Various lawsuits, claims, including claims for asbestos exposure, and proceedings related to our normal business operations, are pending against Met-Ed, the most significant of which are described above. Critical Accounting Policies ---------------------------- Met-Ed prepares its consolidated financial statements in accordance with GAAP. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. All of Met-Ed's assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. Met-Ed's more significant accounting policies are described below. Regulatory Accounting Met-Ed is subject to regulation that sets the prices (rates) it is permitted to charge its customers based on costs that the regulatory agencies determine Met-Ed is permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. Met-Ed regularly reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. Derivative Accounting Determination of appropriate accounting for derivative transactions requires the involvement of management representing operations, finance and risk assessment. In order to determine the appropriate accounting for derivative transactions, the provisions of the contract need to be carefully assessed in accordance with the authoritative accounting literature and management's intended use of the derivative. New authoritative guidance continues to shape the application of derivative accounting. Management's expectations and intentions are key factors in determining the appropriate accounting for a derivative transaction and, as a result, such expectations and intentions are documented. Derivative contracts that are determined to fall within the scope of SFAS 133, as amended, must be recorded at their fair value. Active market prices are not always available to determine the fair value of the later years of a contract, requiring that various assumptions and estimates be used in their valuation. Met-Ed continually monitors its derivative contracts to determine if its activities, expectations, intentions, assumptions and estimates remain valid. As part of its normal operations, Met-Ed enters into commodity contracts, as well as interest rate swaps, which increase the impact of derivative accounting judgments. Revenue Recognition Met-Ed follows the accrual method of accounting for revenues, recognizing revenue for electricity that has been delivered to customers but not yet billed through the end of the accounting period. The determination of 143 electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimated and a corresponding accrual for unbilled revenues is recognized. The determination of unbilled revenues requires management to make estimates regarding electricity available for retail load, transmission and distribution line losses, consumption by customer class and electricity provided by alternative suppliers. Pension and Other Postretirement Benefits Accounting FirstEnergy's pension and post-retirement benefit obligations are allocated to its subsidiaries employing the plan participants. Employee benefits related to construction projects are capitalized. Met-Ed's reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions to the plans, and earnings on plan assets. Such factors may be further affected by business combinations (such as FirstEnergy's merger with GPU in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs are also affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. In accordance with SFAS 87 and SFAS 106, changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. FirstEnergy reduced its assumed discount rate as of December 31, 2003 to 6.25% from 6.75% used as of December 31, 2002. FirstEnergy's assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. In 2003 and 2002, plan assets actually earned 24.0% and (11.3)%, respectively. FirstEnergy's pension costs in 2003 and the first half of 2004 were computed assuming a 9.0% rate of return on plan assets based upon projections of future returns and its pension trust investment allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash. Based on pension assumptions and pension plan assets as of December 31, 2003, FirstEnergy will not be required to fund its pension plans in 2004. Health care cost trends have significantly increased and will affect future OPEB costs. The 2004 and 2003 composite health care trend rate assumptions are approximately 10%-12% gradually decreasing to 5% in later years. In determining its trend rate assumptions, FirstEnergy included the specific provisions of its health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in its health care plans, and projections of future medical trend rates. Long-Lived Assets In accordance with SFAS 144, Met-Ed periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset might not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment has occurred, Met-Ed recognizes a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). The calculation of future cash flows is based on assumptions, estimates and judgment about future events. The aggregate amount of cash flows determines whether an impairment is indicated. The timing of the cash flows is critical in determining the amount of the impairment. Nuclear Decommissioning In accordance with SFAS 143, Met-Ed recognizes an ARO for the future decommissioning of TMI-2. The ARO liability represents an estimate of the fair value of Met-Ed's current obligation related to nuclear decommissioning. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. Met-Ed used an expected cash flow approach (as 144 discussed in FCON 7) to measure the fair value of the nuclear decommissioning ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. Goodwill In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, Met-Ed evaluates goodwill for impairment at least annually and would make such an evaluation more frequently if indicators of impairment should arise. In accordance with the accounting standard, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. If impairment were to be indicated, Met-Ed would recognize a loss - calculated as the difference between the implied fair value of its goodwill and the carrying value of the goodwill. Met-Ed's most recent annual review was completed in the third quarter of 2003, with no impairment indicated. The forecasts used in Met-Ed's evaluations of goodwill reflect operations consistent with its general business assumptions. Unanticipated changes in those assumptions could have a significant effect on Met-Ed's future evaluations of goodwill. In the first half of 2004, Met-Ed reduced goodwill by $7 million for pre-merger interest received on an income tax refund and other tax benefits. As of June 30, 2004, Met-Ed had $877 million of goodwill. New Accounting Standards And Interpretations -------------------------------------------- EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary and Its Application to Certain Investments" On March 31, 2004, the FASB ratified the consensus reached by the EITF 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 are to be applied to other-than-temporary impairment evaluations in reporting periods beginning after June 15, 2004. Met-Ed does not expect the adoption of EITF 03-1 to have a material impact on its consolidated 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 the 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. See Note 4 for a discussion of the effect of the federal subsidy provided under the Medicare Act on the consolidated financial statements. FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities" In December 2003, the FASB issued a revised interpretation of Accounting Research Bulletin No. 51, "Consolidated Financial Statements", 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, Met-Ed 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 Met-Ed's consolidated financial statements. 145 PENNSYLVANIA ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (Unaudited)

PENNSYLVANIA ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS (Unaudited)

PENNSYLVANIA ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Stockholders and Board of Directors of Pennsylvania Electric Company: We have reviewed the accompanying consolidated balance sheet of Pennsylvania Electric Company and its subsidiaries as of June 30, 2004, and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and six-month periods ended June 30, 2004 and 2003. These interim financial statements are the responsibility of the Company's management. We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America. As discussed in Note 2 to the consolidated interim financial statements, the Company has restated its previously issued consolidated interim financial statements for the three-month and six-month periods ended June 30, 2003. We previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet and the consolidated statement of capitalization as of December 31, 2003, and the related consolidated statements of income, common stockholder's equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company's change in its method of accounting for asset retirement obligations as of January 1, 2003 as discussed in Note 1(E) to those consolidated financial statements and the Company's change in its method of accounting for the consolidation of variable interest entities as of December 31, 2003 as discussed in Note 8 to those consolidated financial statements) dated February 25, 2004 we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2003, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived. PricewaterhouseCoopers LLP Cleveland, Ohio August 6, 2004 149 PENNSYLVANIA ELECTRIC COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Penelec is a wholly owned, electric utility subsidiary of FirstEnergy. Penelec provides regulated transmission and distribution services in western Pennsylvania. Pennsylvania customers are able to choose their electricity suppliers as a result of legislation which restructured the electric utility industry. Penelec's regulatory plan required unbundling the price for electricity into its component elements - including generation, transmission, distribution and transition charges. Penelec continues to deliver power to homes and businesses through its existing distribution system and maintains PLR obligations to customers who elect to retain Penelec as their power supplier. Restatements Of Previously Reported Quarterly Results ----------------------------------------------------- As discussed in Note 2 to the Consolidated Financial Statements, Penelec's quarterly results for the second quarter of 2003 have been restated to correct the amounts reported for operating expenses. Penelec's costs which were originally recorded as operating expenses and should have been capitalized to construction were $0.7 million ($0.4 million after-tax) in the second quarter of 2003. The impact of these adjustments was not material to Penelec's Consolidated Balance Sheets or Consolidated Statements of Cash Flows for any quarter of 2003. In addition, as further discussed in Note 8 to the Consolidated Financial Statements, amounts for purchased power, other operating costs and provisions for depreciation and amortization in Penelec's 2003 Consolidated Statements of Income were reclassified to conform with the current year presentation of generation commodity costs. These reclassifications did not change previously reported results in 2003. Results of Operations -------------------- Net income in the second quarter of 2004 decreased to $3.0 million from $8.7 million in the second quarter of 2003. Higher operating revenues were more than offset by increased purchased power, other operating costs and net interest charges as compared to the second quarter of 2003. During the first six months of 2004, net income decreased to $8.7 million compared to $14.0 million in the first six months of 2003. Net income in the first half of 2003 included an after-tax credit of $1.1 million from the cumulative effect of an accounting change due to the adoption of SFAS 143. Income before the cumulative effect was $8.7 million in the first six months of 2004, compared to $12.9 million for the same period in 2003. The decrease in net income was the result of higher purchased power costs, other operating costs and interest charges -partially offset by higher operating revenues. Operating revenues increased by $10.3 million, or 4.4% in the second quarter of 2004 compared with the same period in 2003, primarily as a result of higher distribution and generation revenues. Revenues from electricity throughput increased by $11.2 million as a result of higher unit prices ($4.7 million) and a 7.1% increase in distribution deliveries. Penelec's distribution deliveries increased in all sectors - including a 13.3% increase in industrial deliveries in part due to an improving economy. Retail generation kilowatt-hour sales increased by 8.3% as a result of higher kilowatt-hour sales to industrial and commercial sectors, due to more customers returning from alternative suppliers. Operating revenues increased $11.8 million, or 2.4% in the first six months of 2004 compared to the same period in 2003, reflecting a 3.2% increase in distribution deliveries and a corresponding increase in revenues of $20.4 million. Higher distribution deliveries to industrial, commercial and residential customer sectors and higher transition revenues contributed to this increase. Higher revenues from distribution deliveries were partially offset by lower generation revenues of $4.5 million resulting from lower unit prices. The change in unit prices for generation and distribution transition revenues reflected the impact of the October 2003 PPUC order to change those rates to the previous PPUC Restructuring Settlement order levels (see Regulatory Matters). This change resulted in lower generation revenues unit prices and the corresponding increase in distribution transition revenue unit prices. Changes in electric generation sales and distribution deliveries in the second quarter and the first six months of 2004 from the corresponding periods of 2003 are summarized in the following table: 150 Changes in Kilowatt-Hour Sales Three Months Six Months ------------------------------------------------------------------------- Increase (Decrease) Electric Generation: Retail................................ 8.3% 4.8% Wholesale............................. (100.0)% (100.0)% --------------------------------------------------------------------- Total Electric Generation Sales......... 7.7% 4.7% ==================================================================== Distribution Deliveries: Residential........................... 1.7% 2.6% Commercial............................ 5.6% 2.5% Industrial............................ 13.3% 4.6% -------------------------------------------------------------------- Total Distribution Deliveries........... 7.1% 3.2% ==================================================================== Operating Expenses and Taxes Total operating expenses and taxes increased $13.7 million or 6.3% in the second quarter of 2004 and $12.4 million, or 2.7% in the first six months of 2004 from the same periods of 2003. The following table presents changes from the prior year by expense category. Operating Expenses and Taxes - Changes Three Months Six Months -------------------------------------------------------------------------------- Increase (Decrease) (In millions) Purchased power costs.......................... $11.9 $13.1 Other operating costs.......................... 5.1 2.0 --------------------------------------------------------------------------- Total operation and maintenance expenses..... 17.0 15.1 Provision for depreciation and amortization.... (0.3) (0.6) General taxes.................................. 1.1 2.3 Income taxes................................... (4.1) (4.4) --------------------------------------------------------------------------- Total operating expenses and taxes........... $13.7 $12.4 =========================================================================== Higher purchased power costs in the second quarter of 2004 reflect additional kilowatt-hours purchased to support increased generation sales requirements, as well as higher unit costs. The higher purchased power costs in the first half of 2004 were principally due to additional kilowatt-hours purchased to support increased generation sales requirements. The increase in other operating costs in the second quarter and first half of 2004 compared to the same periods of 2003 primarily resulted from an increase of $8.5 million for PJM transmission costs (which were assumed by Penelec in the second quarter of 2004 due to a change in the PLR agreement with FES) and higher energy delivery costs related to increased vegetation management activities, partially offset by decreased employee benefit costs. Net Interest Charges Net interest charges increased by $2.2 million in the second quarter of 2004 and $3.7 million in the first half of 2004 compared with the same periods of 2003, primarily due to Penelec changing from a net lender to the money pool with associated companies in 2003 to a net borrower in 2004. The change in funding position resulted from a $51 million refunding payment to a NUG trust fund in 2004 compared to a $106 million withdrawal from the NUG trust in 2003. Cumulative Effect of Accounting Change Upon adoption of SFAS 143 in the first quarter of 2003, Penelec recorded an after-tax credit to net income of $1.1 million. The cumulative effect adjustment for unrecognized depreciation and accretion offset by the reduction in the existing decommissioning liabilities and ceasing the accounting practice depreciating non-regulated generation assets using a cost of removal component was an $1.9 million increase to income, or $1.1 million net of income taxes. Capital Resources and Liquidity ------------------------------- Penelec's cash requirements in 2004 for operating expenses, construction expenditures and scheduled debt maturities are expected to be met without materially increasing its net debt and preferred stock outstanding. Over the next two years, Penelec expects to meet its contractual obligations with cash from operations. Thereafter, Penelec expects to use a combination of cash from operations and funds from the capital markets. Changes in Cash Position There was no change as of June 30, 2004 and December 31, 2003 in Penelec's cash and cash equivalents of $36,000. 151 Cash Flows From Operating Activities Cash used for operating activities during the second quarter and first six months of 2004 compared with the corresponding periods of 2003 were as follows: Three Months Ended Six Months Ended June 30, June 30, --------------------------------------------------------------------- Operating Cash Flows 2004 2003 2004 2003 --------------------------------------------------------------------- (In millions) Cash earnings (loss) (1)... $(14) $35 $29 $10 Working capital and other.. 88 29 18 34 -------------------------------------------------------------------- Total...................... $ 74 $64 $47 $44 ==================================================================== (1) Includes net income, depreciation and amortization, deferred costs recoverable as regulatory assets, deferred income taxes, investment tax credits and pension changes. Net cash provided from operating activities increased to $74 million in the second quarter and $47 million in the first half of 2004 compared with the corresponding periods of 2003 of $64 million and $44 million, respectively. The $10 million increase in the second quarter of 2004 was due to the $59 million increase in working capital partially offset by $49 million lower cash earnings resulting from lower net income and changes in deferred income taxes. For the first half of 2004 the increase was due to higher cash earnings of $19 million due to an increase in deferred income taxes offset by reductions in net incXome, accrued retirement benefits and accrued compensation. The decrease in working capital of $16 million for the six-month period was primarily due to a decrease in accounts payable combined with an increase in accounts receivable, partially offset by a decrease in prepayments. Cash Flows From Financing Activities Net cash used for financing activities increased by $72 million in the second quarter of 2004 from the second quarter of 2003. The increase in cash used primarily resulted from the redemption of $125 million of senior notes in April 2004 - offset in part by the issuance of $69 million in short-term borrowings. Net cash provided from financing activities of $27 million for the first six months of 2004 compared to net cash used for financing activities of $79 million for the first six months of 2003, represents the issuance in March 2004 of $150 million of long-term debt used to redeem $125 million of senior notes in April 2004; Penelec's short-term borrowings were reduced by $63 million in the first six months of 2003. As of June 30, 2004, Penelec had about $86.1 million of short-term indebtedness. Penelec will not issue FMB other than as collateral for senior notes, since its senior note indentures prohibit (subject to certain exceptions) it from issuing any debt which is senior to the senior notes. As of June 30, 2004, Penelec had the capability to issue $11.4 million of additional senior notes based upon FMB collateral. Penelec had no restrictions on the issuance of preferred stock. Penelec has the ability to borrow from its regulated affiliates and FirstEnergy to meet its short-term working capital requirements. FESC administers this money pool and tracks surplus funds of FirstEnergy and its regulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of such a loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from the pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the second quarter of 2004 was 1.39%. In March 2004, Penelec completed a receivables financing arrangement which provides for borrowings of up to $75 million. The borrowing rate is based on bank commercial paper rates. Penelec is required to pay an annual facility fee of 0.30% on the entire finance limit. The facility was undrawn as of June 30, 2004 and matures on March 29, 2005. Penelec's access to capital markets and costs of financing are dependent on the ratings of its securities and the securities of FirstEnergy. The ratings outlook on all of its securities is stable. On April 28, 2004, Moody's published a Liquidity Risk Assessment of FirstEnergy Corp. stating that FirstEnergy had "adequate liquidity." Moody's noted that FirstEnergy's committed credit facilities at the holding company level provided a substantial source of liquidity. Moody's also noted that, in the past year, FirstEnergy had lengthened the average maturity of its bank facilities and had made reductions to its total consolidated debt level. On April 30, 2004, Moody's published a Credit Opinion of FirstEnergy Corp. Moody's cited the stable and predictable cash flows of FirstEnergy's core utility operations, management's focus on increasing financial flexibility via debt reduction and divestiture of non-core assets, and FirstEnergy's integrated regional strategy, and strong liquidity as credit strengths. Moody's noted the substantial debt burden associated with the GPU merger, fully competitive generating markets, and modest growth in markets served as credit challenges for 152 FirstEnergy. Moody's also noted that a "track record of improving financial condition, especially a track record of debt reduction, could cause the ratings to go up" and that the opposite development could cause the ratings to go down. On June 14, S&P stated that the June 9, 2004 PUCO decision on FirstEnergy's Rate Stabilization Plan did not affect the ratings or the outlook on FirstEnergy. Cash Flows From Investing Activities Net cash used for investing activities totaled $13 million in the second quarter of 2004 compared to $75 million in the second quarter of 2003. The lower investing activities reflected reduced loans to associated companies. Net cash used for investing activities was $74 million in the first six months of 2004, compared with net cash of $25 million provided from investing activities in the same period of 2003. The change in net cash resulted from a $51 million refunding payment to a NUG trust fund in 2004 and a $106 million withdrawal from the NUG trust in 2003. Expenditures for property additions primarily support Penelec's energy delivery operations. During the second half of 2004, capital requirements for property additions are expected to be about $36 million. Penelec has additional requirements of approximately $0.2 million for maturing long-term debt during the remainder of 2004. In addition, Penelec announced it would optionally redeem at par $100 million principal amount of its subordinated debentures in connection with the concurrent off-balance sheet redemption at par of $100 million principal amount of Penelec Capital Trusts 7.34% Trust Preferred Securities on September 1, 2004.These cash requirements are expected to be satisfied from internal cash and short-term credit arrangements. Market Risk Information ----------------------- Penelec uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price fluctuations. 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. Commodity Price Risk Penelec is exposed to market risk primarily due to fluctuations in electricity and natural gas prices. To manage the volatility relating to these exposures, it uses a variety of non-derivative and derivative instruments, including options and future contracts. The derivatives are used for hedging purposes. Most of Penelec's non-hedge derivative contracts represent non-trading positions that do not qualify for hedge treatment under SFAS 133. The change in the fair value of commodity derivative contracts related to energy production during the second quarter and first six months of 2004 is summarized in the following table:

153 Derivatives included on the Consolidated Balance Sheet as of June 30, 2004: Non-Hedge Hedge Total --------------------------------------------------------------------------- (In millions) Current- Other Assets....................... $ -- $ -- $ -- Other Liabilities.................. -- -- -- Non-Current- Other Deferred Charges............. 15 -- 15 Other Liabilities.................. -- -- -- --------------------------------------------------------------------------- Net assets......................... $ 15 $ -- $ 15 =========================================================================== The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, Penelec relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. Penelec uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for the valuation of derivative contracts by year are summarized in the following table:

Penelec performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift in quoted market prices in the near term on derivative instruments would not have had a material effect on its consolidated financial position or cash flows as of June 30, 2004. Equity Price Risk Included in Penelec's nuclear decommissioning trust investments are marketable equity securities carried at their market value of approximately $56 million and $54 million as of June 30, 2004 and December 31, 2003, respectively. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $6 million reduction in fair value as of June 30, 2004. Outlook ------- Beginning in 1999, all of Penelec's customers were able to select alternative energy suppliers. Penelec continues to deliver power to homes and businesses through its existing distribution system, which remains regulated. The PPUC authorized Penelec's rate restructuring plan, establishing separate charges for transmission, distribution, generation and stranded cost recovery, which is recovered through a CTC. Customers electing to obtain power from an alternative supplier have their bills reduced based on the regulated generation component, and the customers receive a generation charge from the alternative supplier. Penelec has a continuing responsibility to provide power to those customers not choosing to receive power from an alternative energy supplier, subject to certain limits, which is referred to as its PLR obligation. Regulatory Matters 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 Penelec to defer, for future recovery, energy costs in excess of amounts reflected in its capped generation rates retroactive to January 1, 2001. This PLR deferral accounting procedure was later reversed 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. Penelec established a $111.1 million reserve in 2002 for its PLR deferred energy costs incurred prior to its acquisition by FirstEnergy, reflecting the potential adverse impact of the then pending Pennsylvania Supreme Court decision whether to review the Commonwealth Court decision. The reserve increased goodwill by an aggregate net of tax amount of $65.0 million. 154 On April 2, 2003, the PPUC remanded the issue relating to merger savings to the ALJ for hearings, directed 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. Penelec filed a letter with the ALJ on June 11, 2003, voiding the Stipulation in its entirety and reinstating 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 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 upon one day's notice. In response to that order, Penelec filed supplements to its tariffs to become effective October 24, 2003. On October 8, 2003, 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 its rights to recover all of its stranded costs. On October 9, 2003, ARIPPA (an intervenor in the proceedings) petitioned the PPUC to direct 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 Penelec for the NUG trust fund refund, denying Penelec's other clarification requests and granting ARIPPA's petition with respect to the retroactive accounting treatment of the changes to the CTC rate/shopping credit swap. On October 22, 2003, Penelec filed an Objection with the Commonwealth Court asking that the Court reverse the PPUC's finding that requires Penelec to treat the stipulated CTC rates that were in effect from January 1, 2002 on a retroactive basis. On October 27, 2003, one Commonwealth Court judge issued an Order denying Penelec's Objection without explanation. Due to the vagueness of the Order, Penelec, on October 31, 2003, filed an Application for Clarification with the judge. Concurrent with this filing, Penelec, in order to preserve its 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 Penelec's Objection was intended to be denied on the merits. In addition to these findings, 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. Penelec purchases a portion of its 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 Penelec under its NUG contracts and other power contracts with nonaffiliated third party suppliers. This arrangement reduces Penelec's exposure to high wholesale power prices by providing power at a fixed price for its uncommitted PLR energy costs during the term of the agreement with FES. FES has hedged most of 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. Penelec is authorized to continue deferring differences between NUG contract costs and current market prices. Regulatory assets are costs which have been authorized by the PPUC and the FERC for recovery from customers in future periods and, without such authorization, would have been charged to income when incurred. All of Penelec's regulatory assets are expected to continue to be recovered under the provisions of the regulatory plan as discussed below. Penelec's regulatory assets were $411 million and $497 million as of June 30, 2004 and December 31, 2003, respectively. Environmental Matters Penelec has been named as a PRP at waste disposal sites which may require cleanup under the Comprehensive Environmental Response, Compensation and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site be held liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheets, based on estimates of the total costs of cleanup, Penelec's proportionate responsibility for such costs and the financial ability of other nonaffiliated entities to pay. Penelec has accrued liabilities aggregating approximately $26,000 as of June 30, 2004. Penelec accrues environmental liabilities only when it can conclude that it is probable that an obligation for such costs exists and can reasonably determine the amount of such costs. Unasserted claims are reflected in Penelec's determination of environmental liabilities and are accrued in the period that they are both probable and reasonably estimable. 155 Power Outage On August 14, 2003, various states and parts of southern Canada experienced a widespread power outage. That outage 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 this outage. In the final report, the Task Force concluded, among other things, that the problems leading to the outage began in FirstEnergy's Ohio service area. Specifically, the final report concludes, among other things, that the initiation of the August 14th power outage resulted from the coincidence on that afternoon of several events, including: 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 14th power outage and that it does not adequately address the underlying causes of the outage. FirstEnergy remains convinced that the outage cannot be explained by events on any one utility's system. 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 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 14th power outage, 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 Reliability Initiatives 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 June 30, 2004 for any expenditures in excess of those actually incurred through that date. Reliability Initiatives On October 15, 2003, NERC issued a letter to all NERC control areas and reliability coordinators requesting that a review of various reliability practices be undertaken within 60 days. The Company issued its response on December 15, 2003, confirming that its review had taken place and noted that it was undertaking various enhancements to current practices. On February 10, 2004, NERC issued its Recommended Actions to Prevent and Mitigate the Impacts of Future Cascading Blackouts. Approximately 20 of the recommendations were directed at the FirstEnergy companies and broadly focused on initiatives that were recommended for completion by June 30, 2004. These initiatives principally related to: changes in voltage criteria and reactive resources management; operational preparedness and action plans; emergency response capabilities; and preparedness and operating center training. FirstEnergy presented a detailed implementation plan to NERC, which the NERC Board of Trustees subsequently endorsed on May 7, 2004. The various initiatives required by NERC to be completed by June 30, 2004 have been certified as complete to NERC (on June 30, 2004), with one minor exception related to reactive testing of certain generators expected to be completed later this year. An independent NERC verification team conducted an on-site review of the completion status, reporting on July 14, 2004, that FirstEnergy had implemented the policies, procedures and actions that were recommended to be completed by June 30, 2004, with the exception noted by FirstEnergy. Implementation of the recommendations has not required incremental material investment or upgrades to existing equipment. On April 5, 2004, the U.S. - Canada Power System Outage Task Force issued a Final Report on the August 14, 2003 power outage. 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 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 recommendations on June 30, 2004. Implementation of the recommendations has not required incremental material investment or upgrades to existing equipment. 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 thereafter assembled an independent verification team to confirm implementation of NERC Recommended Actions to Prevent and Mitigate the Impacts of Future Cascading Blackouts required to be completed by June 30, 2004, as well as NERC recommendations contained in the Control Area Readiness Audit Report required to be completed by summer 2004, and recommendations in the Joint U.S. - Canada Power System Outage Task Force Report directed toward FirstEnergy and required to be completed by June 30, 2004. The NERC team reported, on July 14, 2004, that FirstEnergy has completed the 156 recommended policies, procedures, and actions required to be completed by June 30, 2004 or summer 2004, with exceptions noted by FirstEnergy. 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 Penelec. 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. Penelec 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. Penelec is unable to predict the outcome of this proceeding. On January 16, 2004, the PPUC initiated a formal investigation of whether Penelec's "service reliability performance deteriorated to a point below the level of service reliability that existed prior to restructuring" in Pennsylvania. Discovery has commenced in the proceeding and Penelec's testimony was filed May 7, 2004. On June 21, 2004, intervenors filed rebuttal testimony and Penelec's surrebuttal testimony was filed on July 23, 2004. Hearings were held in early August 2004 and the ALJ has been directed to issue a Recommended Decision by September 30, 2004, in order to allow the PPUC time to issue a Final Order by the end of 2004. Penelec is unable to predict the outcome of the investigation or the impact of the PPUC order. Legal Matters Various lawsuits, claims, including claims for asbestos exposure, and proceedings related to Penelec's normal business operations are pending against it, the most significant of which are described above. Critical Accounting Policies ---------------------------- Penelec prepares its consolidated financial statements in accordance with GAAP. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect its financial results. All of Penelec's assets are subject to their own specific risks and uncertainties and are regularly reviewed for impairment. Assets related to the application of the policies discussed below are similarly reviewed with their risks and uncertainties reflecting these specific factors. Penelec's more significant accounting policies are described below. Regulatory Accounting Penelec is subject to regulation that sets the prices (rates) it is permitted to charge its customers based on the costs that the regulatory agencies determine Penelec is permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This rate-making process results in the recording of regulatory assets based on anticipated future cash inflows. Penelec regularly reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. Derivative Accounting Determination of appropriate accounting for derivative transactions requires the involvement of management representing operations, finance and risk assessment. In order to determine the appropriate accounting for derivative transactions, the provisions of the contract need to be carefully assessed in accordance with the authoritative accounting literature and management's intended use of the derivative. New authoritative guidance continues to shape the application of derivative accounting. Management's expectations and intentions are key factors in determining the appropriate accounting for a derivative transaction and, as a result, such expectations and intentions are documented. Derivative contracts that are determined to fall within the scope of SFAS 133, as amended, must be recorded at their fair value. Active market prices are not always available to determine the fair value of the later years of a contract, requiring that various assumptions and estimates be used in their valuation. Penelec continually monitors its derivative contracts to determine if its activities, expectations, intentions, assumptions and estimates remain valid. As part of its normal operations, Penelec enters into commodity contracts which increase the impact of derivative accounting judgments. Revenue Recognition Penelec follows the accrual method of accounting for revenues, recognizing revenue for electricity that has been delivered to customers but not yet billed through the end of the accounting period. The determination of 157 electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimated and a corresponding accrual for unbilled revenues is recognized. The determination of unbilled revenues requires management to make estimates regarding electricity available for retail load, transmission and distribution line losses, demand by customer class and electricity provided by alternative suppliers. Pension and Other Postretirement Benefits Accounting FirstEnergy's pension and post-retirement benefit obligations are allocated to its subsidiaries employing the plan participants. Employee benefits related to construction projects are capitalized. Penelec's reported costs of providing non-contributory defined pension benefits and postemployment benefits other than pensions are dependent upon numerous factors resulting from actual plan experience and certain assumptions. Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions to the plans, and earnings on plan assets. Such factors may be further affected by business combinations (such as FirstEnergy's merger with GPU in November 2001), which impacts employee demographics, plan experience and other factors. Pension and OPEB costs are also affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. In accordance with SFAS 87 and SFAS 106 changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants' experience. In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. FirstEnergy reduced its assumed discount rate as of December 31, 2003 to 6.25% from 6.75% used as of December 31, 2002. FirstEnergy's assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by its pension trusts. In 2003 and 2002, plan assets actually earned 24.0% and (11.3)%, respectively. FirstEnergy's pension costs in 2003 and the first half of 2004 were computed assuming a 9.0% rate of return on plan assets based upon projections of future returns and its pension trust investment allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash. Based on pension assumptions and pension plan assets as of December 31, 2003, FirstEnergy is not required to fund its pension plans in 2004. Health care cost trends have significantly increased and will affect future OPEB costs. The 2004 and 2003 composite health care trend rate assumptions are approximately 10%-12% gradually decreasing to 5% in later years. In determining its trend rate assumptions, FirstEnergy included the specific provisions of its health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in its health care plans, and projections of future medical trend rates. Long-Lived Assets In accordance with SFAS 144, Penelec periodically evaluates its long-lived assets to determine whether conditions exist that would indicate that the carrying value of an asset might not be fully recoverable. The accounting standard requires that if the sum of future cash flows (undiscounted) expected to result from an asset is less than the carrying value of the asset, an asset impairment must be recognized in the financial statements. If impairment has occurred, Penelec would recognize a loss - calculated as the difference between the carrying value and the estimated fair value of the asset (discounted future net cash flows). The calculation of future cash flows is based on assumptions, estimates and judgment about future events. The aggregate amount of cash flows determines whether an impairment is indicated. The timing of the cash flows is critical in determining the amount of the impairment. Nuclear Decommissioning In accordance with SFAS 143, Penelec recognizes an ARO for the future decommissioning of TMI-2. The ARO liability represents an estimate of the fair value of Penelec's current obligation related to nuclear decommissioning. A fair 158 value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. Penelec used an expected cash flow approach (as discussed in FCON 7 to measure the fair value of the nuclear decommissioning ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. Goodwill In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Based on the guidance provided by SFAS 142, Penelec evaluates 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, Penelec would recognize a loss - calculated as the difference between the implied fair value of its goodwill and the carrying value of the goodwill. Penelec's most recent annual review was completed in the third quarter of 2003, with no impairment indicated. The forecasts used in Penelec's evaluations of goodwill reflect operations consistent with its general business assumptions. Unanticipated changes in those assumptions could have a significant effect on Penelec's future evaluations of goodwill. In the first six months of 2004, Penelec reduced goodwill by $15 million for pre-merger interest received on an income tax refund and other tax benefits. As of June 30, 2004, Penelec had $884 million of goodwill. New Accounting Standards And Interpretations -------------------------------------------- EITF Issue No. 03-1, "The Meaning of Other-Than-Temporary and Its Application to Certain Investments" On March 31, 2004, the FASB ratified the consensus reached by the EITF 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 are to be applied to other-than-temporary impairment evaluations in reporting periods beginning after June 15, 2004. Penelec does not expect the adoption of EITF 03-1 to have a material impact on its consolidated 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. 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, Penelec 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 Penelec's financial statements for the three and six months ended June 30, 2004. See Note 2 for a discussion of Variable Interest Entities. 159 ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK ------------------------------------------------------------------- See "Management's Discussion and Analysis of Results of Operation and Financial Condition - Market Risk Information" in Item 2 above. ITEM 4. CONTROLS AND PROCEDURES -------------------------------- (a) EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES The applicable registrant's chief executive officer and chief financial officer have reviewed and evaluated the registrant's disclosure controls and procedures, as defined in the Securities Exchange Act of 1934 Rules 13a-15(e) and 15d-15(e), as of the end of the date covered by this report. Based on that evaluation, those officers have concluded that the registrant's disclosure controls and procedures are effective and were designed to bring to their attention material information relating to the registrant and its consolidated subsidiaries by others within those entities. (b) CHANGES IN INTERNAL CONTROLS During the quarter ended June 30, 2004, there were no changes in the registrants' internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the registrants' internal control over financial reporting. 160 PART II. OTHER INFORMATION ---------------------------- ITEM 1. LEGAL PROCEEDINGS Information required for Part II, Item 1 is incorporated by reference to the discussions in Notes 3 and 6 of the Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS (a) The annual meeting of FirstEnergy shareholders was held on May 18, 2004. (b) At this meeting, the following persons were elected to FirstEnergy's Board of Directors: Number of Votes -------------------------- For Withheld ----------- ---------- Paul T. Addison................... 263,606,710 19,612,877 Ernest J. Novak, Jr............... 271,779,183 11,440,404 John M. Pietruski................. 269,383,439 13,836,147 Catherine A. Rein................. 264,438,767 18,780,820 Robert C. Savage.................. 250,908,903 32,310,684 (c) At this meeting, the appointment of PricewaterhouseCoopers LLP, an independent registered public accounting firm, as auditor for the year 2004 was ratified: Number of Votes ----------------------------------------- For Against Abstentions ----------- --------- ----------- 273,904,301 6,586,150 2,729,034 (d) At this meeting, amendments to the Amended Code of Regulations to declassify the Board of Directors were approved (approval required 80% of the common shares entitled to vote): Number of Votes ----------------------------------------- For Against Abstentions ----------- --------- ----------- 272,395,791 7,230,086 3,593,698 (e) At this meeting, amendments to the Amended Articles of Incorporation and Amended Code of Regulations to change certain voting requirements were not approved (approval required 80% of the common shares entitled to vote): Number of Votes ------------------------------------------------------------ Broker For Against Abstentions Non-Votes ----------- --------- ----------- ------------ 236,276,530 8,711,169 3,789,993 34,441,895 (f) At this meeting, the Executive Deferred Compensation Plan was approved (approval required a majority of the votes cast): Number of Votes --------------------------------------------------------------- Broker For Against Abstentions Non-Votes ----------- ---------- ----------- ----------- 198,037,334 46,486,158 4,254,193 34,441,902 (g) At this meeting, the Deferred Compensation Plan for Outside Directors was approved (approval required a majority of the votes cast): Number of Votes -------------------------------------------------------------- Broker For Against Abstentions Non-Votes ----------- ---------- ----------- ----------- 197,684,198 46,761,355 4,332,132 34,441,901 161 (h) At this meeting, a shareholder proposal that all future stock option grants to employees be expensed in FirstEnergy's annual income statement was approved (approval required a majority of the votes cast): Number of Votes ------------------------------------------------------------- Broker For Against Abstentions Non-Votes ----------- ----------- ----------- ----------- 132,425,617 107,442,673 8,940,886 34,410,411 (i) At this meeting, a shareholder proposal requesting that any shareholder rights plan be submitted to shareholder vote was approved (approval required a majority of the votes cast): Number of Votes ------------------------------------------------------------- Broker For Against Abstentions Non-Votes ----------- ---------- ----------- ----------- 171,180,303 73,342,244 4,344,407 34,352,632 (j) At this meeting, a shareholder proposal requesting that FirstEnergy publish semi-annual and annual reports regarding its political contributions was not approved (approval required a majority of votes cast): Number of Votes ------------------------------------------------------------ Broker For Against Abstentions Non-Votes ---------- ----------- ----------- ----------- 22,381,838 208,449,067 17,905,069 34,483,612 (k) At this meeting, a shareholder proposal requesting that certain future severance agreements with senior executives be submitted to shareholder vote was approved (approval required a majority of votes cast): Number of Votes ----------------------------------------------------------- Broker For Against Abstentions Non-Votes ----------- ---------- ----------- --------- 155,305,564 88,627,910 4,941,606 34,344,507 Item 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits Exhibit Number ------- Met-Ed ------ 12 Fixed charge ratios 31.1 Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). 31.2 Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). 32.1 Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350. Penelec ------- 12 Fixed charge ratios 15 Letter from independent registered public accounting firm 31.1 Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). 31.2 Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). 32.1 Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350. JCP&L ----- 12 Fixed charge ratios 31.2 Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). 31.3 Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). 32.2 Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350. 162 FirstEnergy ----------- 15 Letter from independent registered public accounting firm 31.1 Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). 31.2 Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). 32.1 Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350. OE and Penn ----------- 15 Letter from independent registered public accounting firm 31.1 Certification of chief executive officer, as adopted pursuan to Rule 13a-15(e)/15d-(e). 31.2 Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). 32.1 Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350. CEI and TE ---------- 31.1 Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). 31.2 Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-(e). 32.1 Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350. Pursuant to reporting requirements of respective financings, JCP&L, Met-Ed and Penelec are required to file fixed charge ratios as an exhibit to this Form 10-Q. FirstEnergy, OE, CEI, TE and Penn do not have similar financing reporting requirements and have not filed their respective fixed charge ratios. Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, neither FirstEnergy, OE, CEI, TE, Penn, JCP&L, Met-Ed nor Penelec have filed as an exhibit to this Form 10-Q any instrument with respect to long-term debt if the respective total amount of securities authorized thereunder does not exceed 10% of their respective total assets of FirstEnergy and its subsidiaries on a consolidated basis, or respectively, OE, CEI, TE, Penn, JCP&L, Met-Ed or Penelec but hereby agree to furnish to the Commission on request any such documents. (b) Reports on Form 8-K FirstEnergy ----------- FirstEnergy filed the following four reports on Form 8-K since March 31, 2004: A report dated May 24, 2004 reported that the Perry Nuclear Power Plant was expected to return to service the following week. A report dated June 14, 2004 reported that the PUCO issued an order that included major modifications to FirstEnergy's revised Rate Stabilization Plan application. A report dated June 28, 2004 reported that the SEC has requested that FirstEnergy provide information and documents related to the extended outage at the Davis-Besse Nuclear Power Station. A report dated July 27, 2004 reported that FirstEnergy had reached an agreement that resolves all pending securities and derivative lawsuits filed against the Company and certain of its officers and directors. CEI and TE ---------- CEI and TE each filed the following three reports on Form 8-K since March 31, 2004: A report dated May 24, 2004 reported that the Perry Nuclear Power Plant was expected to return to service the following week. A report dated June 14, 2004 reported that the PUCO issued an order that included major modifications to FirstEnergy's revised Rate Stabilization Plan application. A report dated June 28, 2004 reported that the SEC has requested that FirstEnergy provide information and documents related to the extended outage at the Davis-Besse Nuclear Power Station. OE -- OE filed the following two reports on Form 8-K since March 31, 2004: A report dated May 24, 2004 reported that the Perry Nuclear Power Plant was expected to return to service the following week. A report dated June 14, 2004 reported that the PUCO issued an order that included major modifications to FirstEnergy's revised Rate Stabilization Plan application. Penn ---- Penn filed one report on Form 8-K since March 31, 2004: A report dated May 24, 2004 reported that the Perry Nuclear Power Plant was expected to return to service the following week. JCP&L, Met-Ed and Penelec ------------------------- None. 163 SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. August 6, 2004 FIRSTENERGY CORP. Registrant OHIO EDISON COMPANY Registrant THE CLEVELAND ELECTRIC ILLUMINATING COMPANY Registrant THE TOLEDO EDISON COMPANY Registrant PENNSYLVANIA POWER COMPANY Registrant JERSEY CENTRAL POWER & LIGHT COMPANY Registrant METROPOLITAN EDISON COMPANY Registrant PENNSYLVANIA ELECTRIC COMPANY Registrant /s/ Harvey L. Wagner ---------------------------------------- Harvey L. Wagner Vice President, Controller and Chief Accounting Officer 164

TOLEDO EDISON CO 10-Q