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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 THESECURITIES EXCHANGE ACT OF 1934
 For the quarterly period ended September 30, 2004 OR [  ]
    
    TRANSITION REPORT PURSUANT TO
SECTION 13 OR 15(d) OF THESECURITIES EXCHANGE ACT OF 1934
 For the transition period from  to Commission
    
    Registrant; State of Incorporation;
    
    I.R.S. EmployerFile Number
    
    Address; and Telephone Number
    
    Identification No.333-21011
    
    FIRSTENERGY CORP.
    
    34-1843785(An Ohio Corporation)76 South Main StreetAkron, OH  44308Telephone (800)736-34021-2578
    
    OHIO EDISON COMPANY
    
    34-0437786(An Ohio Corporation)76 South Main StreetAkron, OH  44308Telephone (800)736-34021-2323
    
    THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
    
    34-0150020(An Ohio Corporation)c/o FirstEnergy Corp.76 South Main StreetAkron, OH  44308Telephone (800)736-34021-3583
    
    THE TOLEDO EDISON COMPANY
    
    34-4375005(An Ohio Corporation)c/o FirstEnergy Corp.76 South Main StreetAkron, OH  44308Telephone (800)736-34021-3491
    
    PENNSYLVANIA POWER COMPANY
    
    25-0718810(A Pennsylvania Corporation)c/o FirstEnergy Corp.76 South Main StreetAkron, OH  44308Telephone (800)736-34021-3141
    
    JERSEY CENTRAL POWER & LIGHT COMPANY
    
    21-0485010(A New Jersey Corporation)c/o FirstEnergy Corp.76 South Main StreetAkron, OH  44308Telephone (800)736-34021-446
    
    METROPOLITAN EDISON COMPANY
    
    23-0870160(A Pennsylvania Corporation)c/o FirstEnergy Corp.76 South Main StreetAkron, OH  44308Telephone (800)736-34021-3522
    
    PENNSYLVANIA ELECTRIC COMPANY
    
    25-0718085(A Pennsylvania Corporation)c/o FirstEnergy Corp.76 South Main StreetAkron, OH  44308Telephone (800)736-3402




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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: OUTSTANDINGCLASS
    
    AS OF NOVEMBER 4, 2004FirstEnergy Corp., $.10 par value
    
    
    329,836,276Ohio Edison Company, no par value
    
    
    100The Cleveland Electric Illuminating Company, no par value
    
    
    79,590,689The Toledo Edison Company, $5 par value
    
    
    39,133,887Pennsylvania Power Company, $30 par value
    
    
    6,290,000Jersey Central Power & Light Company, $10 par value
    
    
    15,371,270Metropolitan Edison Company, no par value
    
    
    859,500Pennsylvania 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
outages and the outcome, cost and other effects of present and potential legal
and administrative proceedings and claims related to those outages, the final
outcome in the proceeding related to FirstEnergys Application for a Rate
Stabilization Plan in Ohio, the risks and other factors discussed from time to
time in the registrants Securities and Exchange Commission filings, including
their annual report on Form 10-K (as amended) for the year ended December 31,
2003 and other similar factors. The registrants expressly disclaim any current
intention to update any forward-looking statements contained in this document
as a result of new information, future events, or otherwise.




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TABLE OF CONTENTS PagesGlossary of Terms
    
    i-iiiPart I. Financial InformationItems 1. and 2. - Financial Statements and Managements Discussion and Analysis of Results of Operation and Financial ConditionNotes to Consolidated Financial Statements
    
    1-25FirstEnergy Corp.Consolidated Statements of Income
    
    26Consolidated Statements of Comprehensive Income
    
    27Consolidated Balance Sheets
    
    28Consolidated Statements of Cash Flows
    
    29Report of Independent Registered Public Accounting Firm
    
    30Managements Discussion and Analysis of Results of Operations and Financial Condition
    
    31-63Ohio Edison CompanyConsolidated Statements of Income and Comprehensive Income
    
    64Consolidated Balance Sheets
    
    65Consolidated Statements of Cash Flows
    
    66Report of Independent Registered Public Accounting Firm
    
    67Managements Discussion and Analysis of Results of Operations and Financial Condition
    
    68-79The Cleveland Electric Illuminating CompanyConsolidated Statements of Income and Comprehensive Income
    
    80Consolidated Balance Sheets
    
    81Consolidated Statements of Cash Flows
    
    82Report of Independent Registered Public Accounting Firm
    
    83Managements Discussion and Analysis of Results of Operations and Financial Condition
    
    84-94The Toledo Edison CompanyConsolidated Statements of Income and Comprehensive Income
    
    95Consolidated Balance Sheets
    
    96Consolidated Statements of Cash Flows
    
    97Report of Independent Registered Public Accounting Firm
    
    98Managements Discussion and Analysis of Results of Operations and Financial Condition
    
    99-109Pennsylvania Power CompanyConsolidated Statements of Income and Comprehensive Income
    
    110Consolidated Balance Sheets
    
    111Consolidated Statements of Cash Flows
    
    112Report of Independent Registered Public Accounting Firm
    
    113Managements Discussion and Analysis of Results of Operations and Financial Condition
    
    114-121




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TABLE OF CONTENTS (Contd) PagesJersey Central Power & Light CompanyConsolidated Statements of Income and Comprehensive Income
    
    122Consolidated Balance Sheets
    
    123Consolidated Statements of Cash Flows
    
    124Report of Independent Registered Public Accounting Firm
    
    125Managements Discussion and Analysis of Results of Operations and Financial Condition
    
    126-135Metropolitan Edison CompanyConsolidated Statements of Income and Comprehensive Income
    
    136Consolidated Balance Sheets
    
    137Consolidated Statements of Cash Flows
    
    138Report of Independent Registered Public Accounting Firm
    
    139Managements Discussion and Analysis of Results of Operations and Financial Condition
    
    140-149Pennsylvania Electric CompanyConsolidated Statements of Income and Comprehensive Income
    
    150Consolidated Balance Sheets
    
    151Consolidated Statements of Cash Flows
    
    152Report of Independent Registered Public Accounting Firm
    
    153Managements Discussion and Analysis of Results of Operations and Financial Condition
    
    154-163Item 3. Quantitative and Qualitative Disclosures About Market Risk
    
    164Item 4. Controls and Procedures
    
    164Part II. Other InformationItem 1. Legal Proceedings
    
    165Item 2.
Changes in Securities, Use of Proceeds and Issuer Purchases of Equity
Securities
    
    165Item 6. Exhibits
    
    165-166EX-4.1.85 85TH SUPP INDEX-4.1.86 86TH SUPP INDEX-4.2.56 54TH SUPP INDEX-10.41 EMPLOYMENT AGREEMENTEX-10.42 NON-QUALIFYINGEX-10.43 RESTRICTED STOCKEX-10.44 EXECUTIVE BONUS PLANEX-12 RATIO OF EARNINGSEX-15 ACCOUNTANTS REPORTEX-31.1 CERTIFICATION CEOEX-31.2 CERTIFICATION CFOEX-31.3 CERTIFICATIONEX-32.1 RULE 906-CEOEX-32.2 RULE 906




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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 facilitiesAvon
    
    Avon Energy Partners HoldingsCEI
    
    The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiaryCFC
    
    Centerior Funding Corporation, a wholly owned finance subsidiary of CEICompanies
    
    OE, CEI, TE, Penn, JCP&L, Met-Ed and PenelecEmdersa
    
    Empresa Distribuidora Electrica Regional S.A.EUOC
    
    Electric Utility Operating Companies (OE, CEI, TE, Penn, JCP&L, Met-Ed, Penelec, and ATSI)FENOC
    
    FirstEnergy Nuclear Operating Company, operates nuclear generating facilitiesFES
    
    FirstEnergy Solutions Corp., provides energy-related products and servicesFESC
    
    FirstEnergy Service Company, provides legal, financial, and other corporate support servicesFGCO
    
    FirstEnergy Generation Corp., operates nonnuclear generating facilitiesFirstCom
    
    First Communications, LLC, provides local and long-distance telephone serviceFirstEnergy
    
    FirstEnergy Corp., a registered public utility holding companyFSG
    
    FirstEnergy Facilities Services Group, LLC, the parent company of several heating, ventilation
air conditioning and energy management companiesGLEP
    
    Great Lakes Energy Partners, LLC, an oil and natural gas exploration and production ventureGPU
    
    GPU, Inc., former parent of JCP&L, Met-Ed and Penelec, which merged with FirstEnergy on November 7, 2001GPU Capital
    
    GPU Capital, Inc., owned and operated electric distribution systems in foreign countriesGPU Power
    
    GPU Power, Inc., owned and operated generation facilities in foreign countriesGPUS
    
    GPU Service Company, previously provided corporate support servicesJCP&L
    
    Jersey Central Power & Light Company, a New Jersey electric utility operating subsidiaryJCP&L Transition
    
    JCP&L Transition Funding LLC, a Delaware limited liability company and issuer of transition bondsMARBEL
    
    MARBEL Energy Corporation, previously held FirstEnergys interest in GLEPMet-Ed
    
    Metropolitan Edison Company, a Pennsylvania electric utility operating subsidiaryMYR
    
    MYR Group, Inc., a utility infrastructure construction service companyNEO
    
    Northeast Ohio Natural Gas Corp., formerly a MARBEL subsidiaryOE
    
    Ohio Edison Company, an Ohio electric utility operating subsidiaryOE Companies
    
    OE and PennOhio Companies
    
    CEI, OE and TEPenelec
    
    Pennsylvania Electric Company, a Pennsylvania electric utility operating subsidiaryPenn
    
    Pennsylvania Power Company, a Pennsylvania electric utility operating subsidiary of OEPNBV
    
    PNBV Capital Trust, a special purpose entity created by OE in 1996Shippingport
    
    Shippingport Capital Trust, a special purpose entity created by CEI and TE in 1997TE
    
    The Toledo Edison Company, an Ohio electric utility operating subsidiaryTEBSA
    
    Termobarranquilla S.A., Empresa de Servicios PublicosTECC
    
    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 JudgeAOCL
    
    Accumulated Other Comprehensive LossAPB
    
    Accounting Principles BoardAPB 25
    
    APB Opinion No. 25, Accounting for Stock Issued to EmployeesARB 51
    
    Accounting Research Bulletin No. 51, Consolidated Financial StatementsARO
    
    Asset Retirement ObligationASLB
    
    Atomic Safety and Licensing BoardBGS
    
    Basic Generation ServiceCO2
    
    Carbon DioxideCTA
    
    Currency Translation AdjustmentCTC
    
    Competitive Transition ChargeECAR
    
    East Central Area Reliability AgreementEITF
    
    Emerging Issues Task ForceEITF 03-1
    
    EITF Issue No. 03-1, The Meaning of Other-Than-Temporary and Its Application to Certain InvestmentsEITF 03-16
    
    EITF Issue No. 03-16, Accounting for Investments in Limited Liability CompaniesEITF 99-19
    
    EITF Issue No. 99-19, Reporting Revenue Gross as a Principal versus Net as an Agent
 i




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GLOSSARY OF TERMS, Cont. EPA
    
    Environmental Protection AgencyFASB
    
    Financial Accounting Standards BoardFCON 7
    
    FASB Concepts Statement No. 7, Using Cash Flow Information and Present Value in Accounting MeasurementsFERC
    
    Federal Energy Regulatory CommissionFIN
    
    FASB InterpretationFIN 46R
    
    FIN 46 (revised December 2003), Consolidation of Variable Interest EntitiesFMB
    
    First Mortgage BondsFSP
    
    FASB Staff PositionFSP EITF 03-1-1
    
    FASB Staff Position No. EITF Issue 03-1-1, Effective
Date of Paragraphs 10-20 of EITF Issue No. 03-1,The Meaning of
Other-Than-Temporary Impairment and Its Application to Certain InvestmentsFSP 106-1
    
    FASB Staff Position No.106-1, Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug, Improvement and Modernization Act of 2003FSP 106-2
    
    FASB Staff Position No.106-2, Accounting and Disclosure Requirements Related to the Medicare
Prescription Drug, Improvement and Modernization Act of 2003GAAP
    
    Accounting Principles Generally Accepted in the United StatesHVAC
    
    Heating, Ventilation and Air-conditioningIRS
    
    Internal Revenue ServiceISO
    
    Independent System OperatorKWH
    
    Kilowatt-hoursLOC
    
    Letter of CreditMACT
    
    Maximum Achievable Control TechnologiesMedicare Act
    
    Medicare Prescription Drug, Improvement and Modernization Act of 2003MISO
    
    Midwest Independent System Operator, Inc.Moodys
    
    Moodys Investors ServiceMTC
    
    Market Transition ChargeMTN
    
    Medium Term NoteMW
    
    MegawattsNAAQS
    
    National Ambient Air Quality StandardsNERC
    
    North American Electric Reliability CouncilNJBPU
    
    New Jersey Board of Public UtilitiesNOV
    
    Notices of ViolationNOX
    
    Nitrogen OxideNRC
    
    Nuclear Regulatory CommissionNUG
    
    Non-Utility GenerationOCC
    
    Ohio Consumers CounselOCI
    
    Other Comprehensive IncomeOPEB
    
    Other Post-Employment BenefitsPCAOB
    
    Public Company Accounting Oversight Board (United States)PJM
    
    PJM Interconnection ISOPLR
    
    Provider of Last ResortPPUC
    
    Pennsylvania Public Utility CommissionPRP
    
    Potentially Responsible PartyPUCO
    
    Public Utilities Commission of OhioPUHCA
    
    Public Utility Holding Company ActRTC
    
    Regulatory Transition ChargeS&P
    
    Standard & Poors Ratings ServiceSBC
    
    Societal Benefits ChargeSEC
    
    United States Securities and Exchange CommissionSFAS
    
    Statement of Financial Accounting StandardsSFAS 71
    
    SFAS No. 71, Accounting for the Effects of Certain Types of RegulationSFAS 87
    
    SFAS No. 87, Employers Accounting for PensionsSFAS 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 128
    
    SFAS No. 128, Earnings per Share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
 ii




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GLOSSARY OF TERMS, Cont. 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SIP
    
    State Implementation PlanSO2
    
    Sulfur DioxideSPE
    
    Special Purpose EntityTBC
    
    Transition Bond ChargeTMI-1
    
    Three Mile Island Unit 1TMI-2
    
    Three Mile Island Unit 2VIE
    
    Variable Interest Entity
 iii




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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. Penn is a wholly owned subsidiary of OE. JCP&L, Met-Ed and Penelec
were acquired in a merger (which was effective November 7, 2001) with GPU, the
former parent company of JCP&L, Met-Ed and Penelec. The merger was accounted
for by the purchase method of accounting and the applicable effects were
reflected on the financial statements of JCP&L, Met-Ed and Penelec as of the
merger date. FirstEnergys consolidated financial statements also include its
other principal subsidiaries: FENOC, FES and its subsidiary FGCO, FESC,
FirstCom, FSG, GPU Capital, GPU Power and MYR. FirstEnergy and its subsidiaries follow GAAP and comply with the
regulations, orders, policies and practices prescribed by the SEC, FERC and, as
applicable, PUCO, PPUC and NJBPU. The consolidated unaudited financial
statements of FirstEnergy and each of the Companies reflect all normal
recurring adjustments that, in the opinion of management, are necessary to
fairly present results of operations for the interim periods. Certain prior
year amounts have been reclassified to conform with the current year
presentation. In particular, expenses (including transmission and congestion
charges) were reclassified among purchased power, other operating costs and
depreciation and amortization to conform with the current year presentation of
generation commodity costs. As discussed in Note 8, segment reporting in 2003
was reclassified to conform with the current year business segment
organizations and operations. In addition, revenues, expenses and taxes related
to certain divestitures in 2003 have been reclassified and reported net as
discontinued operations (see Note 2) and certain revenues and expenses have
been reclassified and presented on a net basis to conform with the current year
presentation. These statements should be read in conjunction with the financial
statements and notes included in the combined Annual Report on Form 10-K for
the year ended December 31, 2003 for FirstEnergy and the Companies. The
preparation of financial statements in conformity with GAAP requires management
to make periodic estimates and assumptions that affect the reported amounts of
assets, liabilities, revenues and expenses and disclosure of contingent assets
and liabilities. Actual results could differ from those estimates. The reported
results of operations are not indicative of results of operations for any
future period. FirstEnergys and the Companies independent registered public accounting
firm has performed reviews of, and issued reports on, these consolidated
interim financial statements in accordance with standards established by the
PCAOB. Pursuant to Rule 436(c) under the Securities Act of 1933, their reports
of those reviews should not be considered a report within the meaning of
Section 7 and 11 of that Act, and the independent registered public accounting
firms liability under Section 11 does not extend to them. 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: Consolidation FirstEnergy and its subsidiaries consolidate all majority-owned
subsidiaries over which they exercise control and, when applicable, entities
for which they have a controlling financial interest, and VIEs for which
FirstEnergy or any of its subsidiaries is the primary beneficiary. Intercompany
transactions and balances are eliminated in consolidation. Investments in
nonconsolidated affiliates (20-50 percent owned companies, joint ventures and
partnerships) over which FirstEnergy and its subsidiaries have the ability to
exercise significant influence, but not control, are accounted for on the
equity basis. 1




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FIN 46R addresses the consolidation of VIEs, including SPEs, that are not
controlled through voting interests or in which the equity investors do not
bear the residual economic risks and rewards. The first step under FIN 46R is
to determine whether an entity is within the scope of FIN 46R, which occurs if
it is deemed to be a VIE. FirstEnergy and its subsidiaries consolidate VIEs
where they have determined that they are the primary beneficiaries as defined
by FIN 46R. Included in FirstEnergys consolidated financial statements are PNBV and
Shippingport, two VIEs created in 1996 and 1997, respectively, to refinance
debt originally issued in connection with sale and leaseback transactions. PNBV
and Shippingport financial data are included in the consolidated financial
statements of OE and CEI, respectively. PNBV was established to purchase a portion of the lease obligation bonds
issued in connection with OEs 1987 sale and leaseback of its interests in the
Perry Plant and Beaver Valley Unit 2. OE used debt and available funds to
purchase the notes issued by PNBV. Ownership of PNBV includes a three-percent
equity interest by a nonaffiliated third party and a three-percent equity
interest held by OES Ventures, a wholly owned subsidiary of OE. As required by
FIN 46R, consolidation of PNBV by FirstEnergy and OE as of December 31, 2003
changed the previously reported trust investment of $361 million to an
investment in collateralized lease bonds of $372 million. The $11 million
increase represented the minority interest in the total assets of PNBV. Shippingport was established to purchase all of the lease obligation bonds
issued in connection with CEIs and TEs Bruce Mansfield Plant sale and
leaseback transaction in 1987. CEI and TE used debt and available funds to
purchase the notes issued by Shippingport. Consolidation of this entity by CEI
impacted the financial statements of CEI and TE but had no impact on the
consolidated financial statements of FirstEnergy. Prior to the adoption of FIN
46R, the assets and liabilities of Shippingport were included on a
proportionate basis in the financial statements of CEI and TE. Adoption of FIN
46R resulted in the consolidation of Shippingport by CEI as of December 31,
2003. Shippingports note payable to TE of $199 million ($10 million current)
and $208 million ($9 million current) as of September 30, 2004 and December 31,
2003, respectively, is included in long-term debt on CEIs Consolidated Balance
Sheets. Through its investment in PNBV, OE has, and through their investments in
Shippingport, CEI and TE have, variable interests in certain owner trusts that
acquired the interests in the Perry Plant and Beaver Valley Unit 2, in the case
of OE, and the Bruce Mansfield Plant, in the case of CEI and TE. FirstEnergy
concluded that OE, CEI and TE were not the primary beneficiaries of the
relevant owner trusts and were therefore not required to consolidate these
entities. The leases are accounted for as operating leases in accordance with
GAAP. The combined purchase price of $3.1 billion for all of the interests
acquired by the owner trusts in 1987 was funded with debt of $2.5 billion and
equity of $600 million. Each of OE, CEI and TE are exposed to losses under the applicable
sale-leaseback agreements upon the occurrence of certain contingent events that
each company considers unlikely to occur. OE, CEI and TE each have a maximum
exposure to loss under these provisions of approximately $1 billion, which
represents the net amount of casualty value payments upon the occurrence of
specified casualty events that render the applicable plant worthless. Under the
applicable sale and leaseback agreements, OE, CEI and TE have net minimum
discounted lease payments of $696 million, $113 million and $572 million,
respectively, that would not be payable if the casualty value payments are
made. As of September 30, 2004, CEI and TE have recorded above-market lease
obligations related to the Bruce Mansfield Plant and Beaver Valley Unit 2
totaling $1.0 billion (CEI$744 million and TE$299 million), of which $85
million (CEI$60 million and TE$25 million) is current. CEI formed a wholly owned statutory business trust to sell preferred
securities and invest the gross proceeds in 9% subordinated debentures of CEI.
The sole assets of the trust are the subordinated debentures with an aggregate
principal amount of $103 million. The trusts preferred securities are
redeemable at 100% of their principal amount at CEIs option beginning in
December 2006. CEI has effectively provided a full and unconditional guarantee
of the trusts obligations under the preferred securities. Met-Ed and Penelec each formed statutory business trusts for substantially
similar transactions to those of CEI. However, ownership of the Met-Ed and
Penelec trusts is through separate wholly owned limited partnerships. On June
1, 2004, Met-Ed extinguished the subordinated debentures held by its affiliated
trust and redeemed all of the associated 7.35% preferred securities (aggregate
value of $100 million). On September 1, 2004, Penelec extinguished the
subordinated debentures held by its affiliated trust and redeemed all of the
associated 7.34% preferred securities (aggregate value of $100 million). Upon adoption of FIN 46R,the limited partnerships and statutory business
trusts discussed above were no longer consolidated on the financial statements
of FirstEnergy or, as applicable, CEI, Met-Ed or Penelec. As of December 31,
2003 and September 30, 2004, subordinated debentures held by the affiliated
trusts were included in long-term debt of the applicable company and equity
investments in the trusts were included in other investments. FirstEnergy has evaluated its power purchase agreements and determined
that certain NUG entities may be VIEs to the extent they own a plant that sells
substantially all of its output to the Companies and the contract price for
power is correlated with the plants variable costs of production. FirstEnergy,
through its subsidiaries JCP&L, Met-Ed and 2




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Penelec, maintains approximately 30 long-term power purchase agreements with
NUG entities. The agreements were structured pursuant to the Public Utility
Regulatory Policies Act of 1978. FirstEnergy was not involved in the creation
of, and has no equity or debt invested in, these entities. FirstEnergy has determined that for all but nine of these entities,
neither JCP&L, Met-Ed or Penelec have variable interests in the entities or the
entities are governmental or not-for-profit organizations not within the scope
of FIN 46R. JCP&L, Met-Ed or Penelec may hold variable interests in the
remaining nine entities, which sell their output at variable prices that
correlate to some extent with the operating costs of the plants. As required by FIN 46R, FirstEnergy has requested each quarter the
information necessary from these nine entities to determine whether they are
VIEs or whether JCP&L, Met-Ed or Penelec is the primary beneficiary.
FirstEnergy has been unable to obtain the requested information, which in most
cases, was deemed by the requested entity to be competitive and proprietary. As
such, FirstEnergy applied the scope exception that exempts enterprises unable
to obtain the necessary information to evaluate entities under FIN 46R. The
maximum exposure to loss from these entities results from increases in the
variable pricing component under the contract terms and cannot be determined
without the requested data. The purchased power costs from these entities
during the three months and nine months ended September 30, 2004 and 2003 were
as follows: Three Months Ended
    
    Nine Months EndedSeptember 30,
    
    September 30,2004
    
    2003
    
    2004
    
    2003(In millions)JCP&L
    
    $
    36
    
    
    $
    31
    
    
    $
    99
    
    
    $
    89Met-Ed
    
    
    13
    
    
    
    12
    
    
    
    38
    
    
    
    39Penelec
    
    
    7
    
    
    
    7
    
    
    
    20
    
    
    
    20Total
    
    $
    56
    
    
    $
    50
    
    
    $
    157
    
    
    $
    148
 FirstEnergy is required to continue to make exhaustive efforts to obtain
the necessary information in future periods and is unable to determine the
possible impact of consolidating any such entity without this information. Earnings Per Share Basic earnings per share are computed using the weighted average of actual
common shares outstanding during the respective period as the denominator. The
denominator for diluted earnings per share reflects the weighted average of
common shares outstanding plus the potential additional common shares that
could result if dilutive securities and other agreements to issue common stock
were exercised. Stock-based awards to purchase shares of common stock totaling
3.4 million in the nine months ended September 30, 2004 and 3.5 million in the
three months and nine months ended September 30, 2003 were excluded from the
calculation of diluted earnings per share of common stock because their
exercise prices were greater than the average market price of common shares
during the period. No stock-based awards were excluded from the calculation for
the quarter ended September 30, 2004. The following table reconciles the
denominators for basic and diluted earnings per share from Income Before
Discontinued Operations and Cumulative Effect of Accounting Change: Three Months Ended
    
    Nine Months EndedReconciliation of Basic and
    
    September 30,
    
    September 30,Diluted Earnings per Share
    
    2004
    
    2003
    
    2004
    
    2003(In thousands)Income before discontinued operations and
cumulative effect of accounting change
    
    $
    298,622
    
    
    $
    151,693
    
    
    $
    676,666
    
    
    $
    276,408Average Shares of Common Stock Outstanding:Denominator for basic earnings per share
(weighted average shares outstanding)
    
    
    327,499
    
    
    
    299,422
    
    
    
    327,280
    
    
    
    295,825Assumed exercise of dilutive stock options and
awards
    
    
    1,600
    
    
    
    1,329
    
    
    
    1,570
    
    
    
    1,328Denominator for diluted earnings per share
    
    
    329,099
    
    
    
    300,751
    
    
    
    328,850
    
    
    
    297,153Income Before Discontinued Operations and Cumulative
Effect of Accounting Change, per common share:Basic
    
    $
    0.91
    
    
    $
    0.51
    
    
    $
    2.07
    
    
    $
    0.93Diluted
    
    $
    0.91
    
    
    $
    0.50
    
    
    $
    2.06
    
    
    $
    0.93
 3




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##### Table of Contents



Preferred Stock Subject to Mandatory Redemption Long-term debt includes the preferred stock of consolidated subsidiaries
subject to mandatory redemption as of September 30, 2004 and December 31, 2003
in accordance with SFAS 150. Issued in May 2003 and effective July 1, 2003,
SFAS 150 establishes standards for how an issuer classifies and measures
certain financial instruments with characteristics of both liabilities and
equity; certain financial instruments that embody obligations for the issuer
are required to be classified as liabilities. The adoption of SFAS 150 had no
impact on FirstEnergys Consolidated Statements of Income because dividends on
applicable subsidiary preferred stock were previously included in net interest
charges and required no reclassification. CEI and Penn, however, did not
include the preferred dividends on their manditorily redeemable preferred stock
in interest expense for the first six months of 2003, but have included the
dividends in interest charges for the three months ended September 30, 2004 and
2003, and the nine months ended September 30, 2004. Securitized Transition Bonds The consolidated financial statements of FirstEnergy and JCP&L include the
results of JCP&L Transition, a wholly owned limited liability company of JCP&L.
In June 2002, JCP&L Transition sold $320 million of transition bonds to
securitize the recovery of JCP&Ls bondable stranded costs associated with the
previously divested Oyster Creek Nuclear Generating Station. JCP&L did not purchase and does not own any of the transition bonds, which
are included as long-term debt on FirstEnergys and JCP&Ls Consolidated
Balance Sheets. The transition bonds are obligations of JCP&L Transition only
and are collateralized solely by the equity and assets of JCP&L Transition,
which consist primarily of bondable transition property. The bondable
transition property is solely the property of JCP&L Transition. Bondable transition property represents the irrevocable right under New
Jersey law of a utility company to charge, collect and receive from its
customers, through a non-bypassable TBC, the principal amount and interest on
the transition bonds and other fees and expenses associated with their
issuance. JCP&L sold the bondable transition property to JCP&L Transition and,
as servicer, manages and administers the bondable transition property,
including the billing, collection and remittance of the TBC, pursuant to a
servicing agreement with JCP&L Transition. JCP&L is entitled to a quarterly
servicing fee of $100,000 that is payable from TBC collections. Derivative Accounting FirstEnergy is exposed to financial risks resulting from the fluctuation
of interest rates and commodity prices, including electricity, natural gas and
coal. To manage the volatility relating to these exposures, FirstEnergy uses a
variety of non-derivative and derivative instruments, including forward
contracts, options, futures contracts and swaps. The derivatives are used
principally for hedging purposes, and to a lesser extent, for trading purposes.
FirstEnergys Risk Policy Committee, comprised of executive officers, exercises
an independent risk oversight function to ensure compliance with corporate risk
management policies and prudent risk management practices. Derivatives are recognized as assets or liabilities at fair value unless
they qualify for an exception under SFAS 133. All changes in the fair value of
derivatives are recognized currently in earnings unless specific hedge criteria
are met. Gains and losses from derivative contracts that do not qualify as
hedges of commodity price or interest rate risk are included in other operating
expenses. SFAS 133 provides that the effective portion of the gain or loss on a
derivative instrument designated and qualifying as a cash flow hedging
instrument be reported as a component of other comprehensive income and be
reclassified into earnings in the same period during which the hedged
forecasted transaction affects earnings. The ineffective portion of hedge gains
and losses is also included in net income. FirstEnergys primary ongoing
hedging activity involves cash flow hedges of electricity and natural gas
purchases. The maximum periods over which the variability of electricity and
natural gas cash flows are hedged are two and three years, respectively. In
2001, FirstEnergy entered into interest rate derivative transactions to hedge a
portion of the anticipated interest payments on debt related to the GPU
acquisition. Gains and losses from these cash flow hedges were reported in
other comprehensive income and are included in net income over the periods that

the hedged interest payments are made  5, 10 and 30 years. The net deferred loss of $93 million included in AOCL as of September 30,
2004, for derivative hedging activity, as compared to the June 30, 2004 balance
of $100 million in net deferred losses, resulted from a $5 million reduction
related to current hedging activity and a $2 million decrease due to net hedge
losses included in earnings during the three months ended September 30, 2004.
Approximately $12 million (after tax) of the net deferred loss on derivative
instruments in AOCL as of September 30, 2004, is expected to be reclassified to
earnings during the next twelve months as hedged transactions occur. The fair
value of these derivative instruments will fluctuate from period to period
based on various market factors. 4




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##### Table of Contents



FirstEnergy has entered into fair value hedges of fixed-rate, long-term
debt issues to protect against the risk of changes in the fair value of
fixed-rate debt instruments due to lower interest rates. Swap maturities, call
options, fixed interest rates received, and interest payment dates match those
of the underlying debt obligations. As of September 30, 2004, FirstEnergy
maintained fixed-for-floating interest rate swap agreements with an aggregate
notional amount of $1.7 billion. Under these agreements, FirstEnergy receives
fixed cash flows based on the fixed coupons of hedged securities and pays
variable cash flows based on short-term variable market interest rates. The
weighted average fixed interest rate of senior notes and subordinated
debentures hedged by the swap agreements was 5.53%. The interest rate swaps
have effectively converted that rate to a current, weighted average variable
interest rate of 3.02%. Changes in the fair value of derivatives designated as
fair value hedges and the corresponding changes in the fair value of the hedged
risk attributable to a recognized asset, liability, or unrecognized firm
commitment are recorded in earnings. If the fair value hedge is effective, the
amounts recorded will offset in earnings. FirstEnergy did not enter into any
new fixed-for-floating interest rate swap agreements during the third quarter
of 2004. Goodwill In a business combination, the excess of the purchase price over the
estimated fair values of assets acquired and liabilities assumed is recognized
as goodwill. Based on the guidance provided by SFAS 142, FirstEnergy evaluates
its goodwill for impairment at least annually and would make such an evaluation
more frequently if indicators of impairment should arise. In accordance with
the accounting standard, if the fair value of a reporting unit is less than its
carrying value (including goodwill), the goodwill is tested for impairment. If
an impairment is indicated, FirstEnergy recognizes a loss  calculated as the
difference between the implied fair value of a reporting units goodwill and
the carrying value of the goodwill. FirstEnergys 2003 annual review resulted
in a non-cash goodwill impairment charge of $122 million in the third quarter
of 2003, reducing the carrying value of FSG. Of this amount, $117 million was
reported as an operating expense and $5 million was included in the results
from discontinued operations. The impairment charge reflected the slow down in
the development of competitive retail markets and depressed economic conditions
that affected the value of FSG. The fair value of FSG was estimated using
primarily the expected discounted future cash flows. FirstEnergys 2004 annual
review was completed in the third quarter of 2004 with no impairment indicated. As of September 30, 2004, FirstEnergy had $6.1 billion of goodwill that
primarily relates to its regulated services segment. In the first nine months
of 2004, FirstEnergy adjusted goodwill related to the former GPU companies for
interest received on a pre-merger income tax refund and for the reversal of tax
valuation allowances related to income tax benefits realized attributable to
prior period capital loss carryforwards that were offset by capital gains
generated in 2004. A summary of the change in goodwill during the nine months
ended September 30, 2004 is shown below: FirstEnergy
    
    CEI
    
    TE
    
    JCP&L
    
    Met-Ed
    
    Penelec(In millions)Goodwill ReconciliationBalance as of December 31, 2003
    
    $
    6,128
    
    
    $
    1,694
    
    
    $
    505
    
    
    $
    2,001
    
    
    $
    884
    
    
    $
    899Adjustments related to GPU acquisition
    
    
    (27
    )
    
    
    
    
    
    
    
    
    
    
    (5
    )
    
    
    (7
    )
    
    
    (15
    )Balance as of September 30, 2004
    
    $
    6,101
    
    
    $
    1,694
    
    
    $
    505
    
    
    $
    1,996
    
    
    $
    877
    
    
    $
    884
 Asset Retirement Obligations FirstEnergy recognizes a liability for retirement obligations associated
with tangible assets in accordance with SFAS 143. FirstEnergy has identified
applicable legal obligations as defined under the standard for nuclear power
plant decommissioning, reclamation of a sludge disposal pond related to the
Bruce Mansfield Plant and closure of two coal ash disposal sites. The ARO
liability was $1.060 billion as of September 30, 2004 and included $1.046
billion for nuclear decommissioning of the Beaver Valley, Davis-Besse, Perry
and TMI-2 nuclear generating facilities. The Companies share of the obligation
to decommission these units was developed based on site specific studies
performed by an independent engineer. FirstEnergy utilized an expected cash
flow approach (as discussed in FCON 7) to measure the fair value of the nuclear
decommissioning ARO. In the third quarter of 2004, FirstEnergy revised the ARO associated with
TMI-2 as the result of a recently completed study and the anticipated operating
license extension at TMI-1. The abandoned TMI-2 is adjacent to TMI-1 and the
units will be decommissioned on a concurrent timeline. The license holder at
TMI-1 has indicated plans to file for a 20-year extension of its operating
license, which currently expires in 2014. The decrease in the present value of
estimated cash flows associated with the license extension of $202 million, was
partially offset by the $26 million present value of an increase in projected
decommissioning costs. The net decrease in the TMI-2 ARO liability and
corresponding regulatory asset was $176 million (JCP&L  $43 million, Met-Ed -
$89 million and Penelec  $44 million). 5




---



##### Table of Contents



The Companies maintain nuclear decommissioning trust funds that are
legally restricted for purposes of settling the nuclear decommissioning ARO. As
of September 30, 2004, the fair value of the decommissioning trust assets was
$1.462 billion. The following tables provide the beginning and ending aggregate carrying
amount of the ARO and the changes to the balance during the three months and
nine months ended September 30, 2004 and 2003, respectively. Three Months
    
    FirstEnergy
    
    OE
    
    CEI
    
    TE
    
    Penn
    
    JCP&L
    
    Met-Ed
    
    Penelec(In millions)ARO ReconciliationBalance, July 1, 2004
    
    $
    1,217
    
    
    $
    194
    
    
    $
    263
    
    
    $
    188
    
    
    $
    134
    
    
    $
    113
    
    
    $
    216
    
    
    $
    108Liabilities incurred
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Liabilities settled
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Accretion
    
    
    19
    
    
    
    4
    
    
    
    5
    
    
    
    3
    
    
    
    2
    
    
    
    2
    
    
    
    3
    
    
    
    1Revisions in estimated cash flows
    
    
    (176
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (43
    )
    
    
    (89
    )
    
    
    (44
    )Balance, September 30, 2004
    
    $
    1,060
    
    
    $
    198
    
    
    $
    268
    
    
    $
    191
    
    
    $
    136
    
    
    $
    72
    
    
    $
    130
    
    
    $
    65Balance, July 1, 2003
    
    $
    1,145
    
    
    $
    182
    
    
    $
    246
    
    
    $
    178
    
    
    $
    126
    
    
    $
    107
    
    
    $
    204
    
    
    $
    102Liabilities incurred
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Liabilities settled
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Accretion
    
    
    16
    
    
    
    3
    
    
    
    5
    
    
    
    1
    
    
    
    1
    
    
    
    1
    
    
    
    3
    
    
    
    2Revisions in estimated cash flows
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Balance, September 30, 2003
    
    $
    1,161
    
    
    $
    185
    
    
    $
    251
    
    
    $
    179
    
    
    $
    127

    
    
    $
    108
    
    
    $
    207
    
    
    $
    104
 Nine Months
    
    FirstEnergy
    
    OE
    
    CEI
    
    TE
    
    Penn
    
    JCP&L
    
    Met-Ed
    
    Penelec(In millions)ARO ReconciliationBalance, January 1, 2004
    
    $
    1,179
    
    
    $
    188
    
    
    $
    255
    
    
    $
    182
    
    
    $
    130
    
    
    $
    110
    
    
    $
    210
    
    
    $
    105Liabilities incurred
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Liabilities settled
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Accretion
    
    
    57
    
    
    
    10
    
    
    
    13
    
    
    
    9
    
    
    
    6
    
    
    
    5
    
    
    
    9
    
    
    
    4Revisions in estimated cash flows
    
    
    (176
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (43
    )
    
    
    (89
    )
    
    
    (44
    )Balance, September 30, 2004
    
    $
    1,060
    
    
    $
    198
    
    
    $
    268
    
    
    $
    191
    
    
    $
    136
    
    
    $
    72
    
    
    $
    130
    
    
    $
    65Balance, January 1, 2003
    
    $
    1,109
    
    
    $
    176
    
    
    $
    238
    
    
    $
    172
    
    
    $
    122
    
    
    $
    104
    
    
    $
    198
    
    
    $
    99Liabilities incurred
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Liabilities settled
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Accretion
    
    
    52
    
    
    
    9
    
    
    
    13
    
    
    
    7
    
    
    
    5
    
    
    
    4
    
    
    
    9
    
    
    
    5Revisions in estimated cash flows
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Balance, September 30, 2003
    
    $
    1,161
    
    
    $
    185
    
    
    $
    251
    
    
    $
    179
    
    
    $
    127
    
    
    $
    108
    
    
    $
    207
    
    
    $
    104
 Stock-Based Compensation FirstEnergy applies the recognition and measurement principles of APB 25
and related Interpretations in accounting for its stock-based compensation
plans. No material stock-based employee compensation expense is reflected in
net income as all options granted under those plans have exercise prices equal
to the market value of the underlying common stock on the respective grant
dates, resulting in substantially no intrinsic value. In March 2004, the FASB issued an exposure draft of a proposed standard
that, if adopted, will change the accounting for employee stock options and
other equity-based compensation. The proposed standard would require companies
to expense the fair value of stock options determined on the grant date. In
October 2004, the FASB amended the proposed standard to delay its effective
date from January 1, 2005 to interim and annual periods beginning after June
15, 2005 (see Note 7). FirstEnergy will not be able to determine the impact of
the proposed standard until it is issued in final form. The table below
summarizes the effects on the Companys net income and earnings per share had
the Company applied the fair value recognition provisions of SFAS 123 to
stock-based employee compensation in the current reporting periods. 6




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##### Table of Contents



Three Months Ended
    
    Nine Months EndedSeptember 30,
    
    September 30,2004
    
    2003
    
    2004
    
    2003(In thousands)
    
    (In thousands)Net income, as reported
    
    $
    298,622
    
    
    $
    152,719
    
    
    $
    676,666
    
    
    $
    313,333Add back compensation expense
reported in net income, net of tax
(based on APB 25)
    
    
    
    
    
    
    40
    
    
    
    
    
    
    
    131Deduct compensation expense based
upon estimated fair value, net of tax
    
    
    (3,432
    )
    
    
    (3,138
    )
    
    
    (11,025
    )
    
    
    (9,314
    )Adjusted net income
    
    $
    295,190
    
    
    $
    149,621
    
    
    $
    665,641
    
    
    $
    304,150Earnings Per Share of Common Stock BasicAs Reported
    
    $
    0.91
    
    
    $
    0.51
    
    
    $
    2.07
    
    
    $
    1.06Adjusted
    
    $
    0.90
    
    
    $
    0.50
    
    
    $
    2.03
    
    
    $
    1.03DilutedAs Reported
    
    $
    0.91
    
    
    $
    0.50
    
    
    $
    2.06
    
    
    $
    1.05Adjusted
    
    $
    0.90
    
    
    $
    0.50
    
    
    $
    2.02
    
    
    $
    1.02
 Discontinued Operations FirstEnergys discontinued operations consisted of net income of $1
million in the third quarter of 2003 and net losses of $65 million in the first
nine months of 2003 from its Argentina and Bolivia businesses and certain
domestic operations divested in 2003. The related revenues, expenses and taxes
were reclassified from the previously reported Consolidated Statement of Income
for the nine months ended September 30, 2003 and reported as a net amount in
Discontinued Operations. In April 2003, FirstEnergy divested its ownership in
Emdersa through the abandonment of its shares in Emdersas parent company, GPU
Argentina Holdings, Inc. The abandonment was accomplished by relinquishing
FirstEnergys shares to the independent Board of Directors of GPU Argentina
Holdings, relieving FirstEnergy of all rights and obligations relative to this
business. As a result of the abandonment, FirstEnergy recognized a one-time,
non-cash charge of $67 million (no income tax benefit was recognized), or $0.23
per share of common stock, in the second quarter of 2003. This charge resulted
from realizing CTA losses through earnings ($90 million, or $0.30 per share of
common stock), partially offset by the gain recognized from abandoning
FirstEnergys investment in Emdersa ($23 million, or $0.07 per share of common
stock). Since FirstEnergy had previously recorded $90 million of CTA
adjustments in OCI, the net effect of the $67 million charge was an increase in
common stockholders equity of $23 million. FirstEnergy sold its Bolivia
operations, Empresa Guaracachi S.A., in December 2003. Domestic operations sold
in 2003 consisted of three former FSG subsidiaries and the MARBEL subsidiary,
NEO. Cumulative Effect of Accounting Change As a result of adopting SFAS 143 in January 2003, FirstEnergy recorded a
$175 million increase to income, $102 million net of tax, or basic earnings of
$0.35 per share ($0.34 diluted) of common stock in the nine months ended
September 30, 2003. Upon adoption of the accounting standard, FirstEnergy
reversed accrued nuclear plant decommissioning costs of $1.23 billion and
recorded an ARO of $1.11 billion, including accumulated accretion of $507
million for the period from the date the liability was incurred to the date of
adoption. FirstEnergy also recorded asset retirement costs of $602 million as
part of the carrying amount of the related long-lived asset and accumulated
depreciation of $415 million. FirstEnergy recognized a regulatory liability of
$185 million for the transition amounts expected to be recovered through rates
related to the ARO for nuclear decommissioning. The cumulative effect
adjustment also included the reversal of $60 million in accumulated estimated
removal costs for non-regulated generation assets. The impact of adopting SFAS 143 on the financial statements of each of the
Companies effective January 1, 2003, is shown in the table below: OE
    
    CEI
    
    TE
    
    Penn
    
    JCP&L
    
    Met-Ed
    
    Penelec(In millions)Asset retirement costs
    
    $
    134
    
    
    $
    50
    
    
    $
    41
    
    
    $
    78
    
    
    $
    98
    
    
    $
    186
    
    
    $
    93Accumulated depreciation
    
    
    25
    
    
    
    7
    
    
    
    6
    
    
    
    9
    
    
    
    98
    
    
    
    186
    
    
    
    93Asset retirement obligation
    
    
    298
    
    
    
    238
    
    
    
    172
    
    
    
    121
    
    
    
    104
    
    
    
    198
    
    
    
    99Cumulative effect adjustment, pretax
    
    
    54
    
    
    
    73
    
    
    
    44
    

    
    
    18
    
    
    
    
    
    
    
    0.4
    
    
    
    2Cumulative effect adjustment, net of tax
    
    
    32
    
    
    
    42
    
    
    
    26
    
    
    
    11
    
    
    
    
    
    
    
    0.2
    
    
    
    1
 7




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##### Table of Contents



Restatements of TE, JCP&L and Penelec Previously Reported Quarterly
Results Earnings for the three months and nine months ended September 30, 2003
have been restated for TE, JCP&L and Penelec to reflect adjustments to costs
that were subsequently capitalized to construction projects. The results for TE
have also been restated to correct the amount reported for interest expense.
TEs costs, which were originally recorded as operating expenses and
subsequently capitalized to construction, were $1.1 million ($0.7 million
after-tax) and $2.1 million ($1.2 million after-tax) in the third quarter and
the first nine months of 2003, respectively. TEs interest expense was
overstated by $0.3 million ($0.2 million after-tax) and $1.6 million ($1.0
million after-tax) in the third quarter and the first nine months of 2003,
respectively. Similar to TE, JCP&Ls capital costs originally recorded as
operating expenses were $5.8 million ($3.4 million after-tax) and $9.0 million
($5.3 million after-tax) in the third quarter and the first nine months of
2003, respectively. Penelecs capital costs originally recorded as operating
expenses were $2.0 million ($1.2 million after-tax) and $2.7 million ($1.6
million after-tax) in the third quarter and the first nine months of 2003,
respectively. In addition, certain revenues and expenses have been reclassified
and presented on a net basis to conform with the current year presentation (see
Note 1). The impacts of these adjustments were not material to the
consolidated balance sheets or consolidated statements of cash flows for TE,
JCP&L or Penelec for any quarter of 2003. The effects of these adjustments on the consolidated statements of income
previously reported for TE, JCP&L and Penelec for the three months and nine
months ended September 30, 2003 are as follows: TE Three Months Ended
    
    Nine Months EndedSeptember 30, 2003
    
    September 30, 2003As Previously
    
    As
    
    As Previously
    
    AsReported
    
    Restated
    
    Reported
    
    Restated(In thousands)Operating revenues
    
    $
    260,190
    
    
    $
    260,197
    
    
    $
    708,000
    
    
    $
    708,007Operating expenses
    
    
    241,987
    
    
    
    241,447
    
    
    
    686,400
    
    
    
    685,813Operating income
    
    
    18,203
    
    
    
    18,750
    
    
    
    21,600
    
    
    
    22,194Other income
    
    
    5,768
    
    
    
    5,724
    
    
    
    12,644
    
    
    
    12,600Net interest charges
    
    
    8,220
    
    
    
    7,872
    
    
    
    29,605
    
    
    
    27,982Income before cumulative effect
of accounting change
    
    
    15,751
    
    
    
    16,602
    
    
    
    4,639
    
    
    
    6,812Cumulative effect of accounting change
    
    
    
    
    
    
    
    
    
    
    25,550
    
    
    
    25,550Net income
    
    
    15,751
    
    
    
    16,602
    
    
    
    30,189
    
    
    
    32,362Preferred stock dividend requirements
    
    
    2,211
    
    
    
    2,211
    
    
    
    6,627
    
    
    
    6,627Earnings attributable to common stock
    
    $
    13,540
    
    
    $
    14,391
    
    
    $
    23,562
    
    
    $
    25,735
 JCP&L Three Months Ended
    
    Nine Months EndedSeptember 30, 2003
    
    September 30, 2003As Previously
    
    As
    
    As Previously
    
    AsReported
    
    Restated
    
    Reported
    
    Restated(In thousands)Operating revenues
    
    $
    743,145
    
    
    $
    741,293
    
    
    $
    1,942,868
    
    
    $
    1,941,016Operating expenses
    
    
    659,526
    
    
    
    653,761
    
    
    
    1,807,539
    
    
    
    1,799,876Operating income
    
    
    83,619
    
    
    
    87,532
    
    
    
    135,329
    
    
    
    141,140Other income
    
    
    1,061
    
    
    
    557
    
    
    
    4,501
    
    
    
    3,997Net interest charges
    
    
    20,517
    
    
    
    20,517
    
    
    
    65,429
    
    
    
    65,429Net income
    
    
    64,163
    
    
    
    67,572
    
    
    
    74,401
    
    
    
    79,708Preferred stock dividend requirements
    
    
    125
    
    
    
    125
    
    
    
    (238
    )
    
    
    (238
    )Earnings attributable to common stock
    
    $
    64,038
    
    
    $
    67,447
    
    
    $
    74,639
    
    
    $
    79,946
 8




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Penelec Three Months Ended
    
    Nine Months EndedSeptember 30, 2003
    
    September 30, 2003As Previously
    
    As
    
    As Previously
    
    AsReported
    
    Restated
    
    Reported
    
    Restated(In thousands)Operating revenues
    
    $
    242,960
    
    
    $
    242,146
    
    
    $
    729,762
    
    
    $
    728,948Operating expenses
    
    
    230,484
    
    
    
    228,476
    
    
    
    688,725
    
    
    
    686,311Operating income
    
    
    12,476
    
    
    
    13,670
    
    
    
    41,037
    
    
    
    42,637Other income
    
    
    545
    
    
    
    522
    
    
    
    887
    
    
    
    864Net interest charges
    
    
    9,046
    
    
    
    9,046
    
    
    
    25,451
    
    
    
    25,451Income before cumulative effect
of accounting change
    
    
    3,975
    
    
    
    5,146
    
    
    
    16,473
    
    
    
    18,050Cumulative effect of accounting change
    
    
    
    
    
    
    
    
    
    
    1,096
    
    
    
    1,096Net income
    
    $
    3,975
    
    
    $
    5,146
    
    
    $
    17,569
    
    
    $
    19,146
 3  COMMITMENTS, GUARANTEES AND CONTINGENCIES: Capital Expenditures FirstEnergys current forecast reflects expenditures of approximately $2.3
billion (OE$295 million, CEI$275 million, TE$141 million, Penn$143 million,
JCP&L$446 million, Met-Ed$168 million, Penelec$198 million, ATSI$66
million, FES$443 million and other subsidiaries$125 million) for property
additions and improvements from 2004-2006, of which approximately $717 million
(OE$113 million, CEI$92 million, TE$48 million, Penn$65 million, JCP&L$142
million, Met-Ed$53 million, Penelec$60 million, ATSI$24 million, FES$87
million and other subsidiaries-$33 million) is applicable to 2004. Investments
for additional nuclear fuel during the 2004-2006 period are estimated to be
approximately $303 million (OE$84 million, CEI$100 million, TE$64 million
and Penn$55 million), of which approximately $90 million (OE$26 million,
CEI$30 million, TE$16 million and Penn$18 million) applies to 2004. Guarantees and Other Assurances As part of normal business activities, FirstEnergy and the Companies enter
into various agreements to provide financial or performance assurances to third
parties. As of September 30, 2004, outstanding guarantees and other assurances
aggregated $2.1 billion and included contract guarantees ($1.0 billion), surety
bonds ($0.3 billion) and letters of credit ($0.8 billion). FirstEnergy guarantees energy and energy-related payments of its
subsidiaries involved in energy marketing activities  principally to
facilitate normal physical transactions involving electricity, gas, emission
allowances and coal. FirstEnergy also provides guarantees to various providers
of subsidiary financing principally for the acquisition of property, plant and
equipment. These agreements legally obligate FirstEnergy and its subsidiaries
to fulfill the obligations of those subsidiaries directly involved in energy
and energy-related transactions or financing where the law might otherwise
limit the counterparties claims. If demands of a counterparty were to exceed
the ability of a subsidiary to satisfy existing obligations, FirstEnergys
guarantee enables the counterpartys legal claim to be satisfied by other
FirstEnergy assets. The likelihood is remote that such parental guarantees of
$0.9 billion (included in the $1.0 billion discussed above) as of September 30,
2004 will increase amounts otherwise to be paid by FirstEnergy to meet its
obligations incurred in connection with financings and ongoing energy and
energy-related activities. While guarantees are normally parental commitments for the future payment
of subsidiary obligations, subsequent to the occurrence of a credit rating
downgrade or material adverse event the immediate payment of cash collateral
or provision of an LOC may be required. The following table summarizes
collateral provisions as of September 30, 2004: Collateral PaidTotal
    
    
    
    RemainingCollateral Provisions
    
    Exposure(1)
    
    Cash
    
    Letters of Credit
    
    Exposure(In millions)Rating downgrade
    
    $
    358
    
    
    $
    145
    
    
    $
    18
    
    
    $
    195Adverse event
    
    
    113
    
    
    
    
    
    
    
    23
    
    
    
    90Total
    
    $
    471
    
    
    $
    145
    
    
    $
    41
    
    
    $
    285
  (1)
    
    As of October 12, 2004, FirstEnergys total
exposure decreased to $465 million and the remaining
exposure decreased to $272 million  net of $152
million of cash collateral and $41 million of LOC
provided to counterparties. 9




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Most of FirstEnergys surety bonds are backed by various indemnities
common within the insurance industry. Surety bonds and related FirstEnergy
guarantees of $280 million provide additional assurance to outside parties that
contractual and statutory obligations will be met in a number of areas
including construction jobs, environmental commitments and various retail
transactions. In connection with the sale of the TEBSA project in Colombia in January
2004, FirstEnergy guaranteed the obligations of the operators of the project,
up to a maximum of $6 million (subject to escalation) under the projects
operation and maintenance agreement for so long as such obligations exist. The
purchaser of TEBSA agreed to indemnify FirstEnergy against any loss under this
guarantee. Also in connection with the TEBSA project, FirstEnergy has provided
the TEBSA project lenders with a $60 million LOC and a $400,000 LOC. The $60
million LOC was established as a substitute asset for FirstEnergys interest in
its Midlands companies pursuant to an indemnity agreement in favor of the TEBSA
project lenders. As of October 15, 2004, the value of the LOC decreased to $46
million. The balance will continue to decline annually and will be fully
discharged and released in October 2010. The substitute LOC enabled
FirstEnergy to sell its remaining 20.1% interest in Avon (parent of Midlands
Electricity in the United Kingdom). The $400,000 LOC was established to secure
the TEBSA project lenders in the event that liquidated shares of TEBSA were
unable to be converted into U.S. currency. The $400,000 LOC will terminate
upon the registration of certain of TEBSAs stock with the Colombian Central
Bank. Environmental Matters Various federal, state and local authorities regulate the Companies with
regard to air and water quality and other environmental matters. The effects of
compliance on the Companies with regard to environmental matters could have a
material adverse effect on FirstEnergys earnings and competitive position.
These environmental regulations affect FirstEnergys earnings and competitive
position to the extent that it competes with companies that are not subject to
such regulations and therefore do not bear the risk of costs associated with
compliance, or failure to comply, with such regulations. Overall, FirstEnergy
believes it is in material compliance with existing regulations but is unable
to predict future change in regulatory policies and what, if any, the effects
of such change would be. FirstEnergy estimates additional capital expenditures
for environmental compliance of approximately $91 million for 2004 through
2006, which is included in the $2.3 billion of forecasted capital expenditures
for 2004 through 2006. Clean Air Act Compliance The
Companies are required to meet federally approved SO2 regulations.
Violations of such regulations can result in shutdown of the generating unit
involved and/or civil or criminal penalties of up to $31,500 for each day the
unit is in violation. The EPA has an interim enforcement policy for SO2
regulations in Ohio that allows for compliance based on a 30-day averaging
period. The Companies cannot predict what action the EPA may take in the future
with respect to the interim enforcement policy. The Companies believe they are complying with SO2 reduction requirements
under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel,
generating more electricity from lower-emitting plants, and/or using emission
allowances. 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. SIPs 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 10




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##### Table of Contents



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 Compliance Orders to nine
utilities covering 44 power plants, including the W. H. Sammis Plant, which is
owned by OE and Penn. In addition, the U.S. Department of Justice filed eight
civil complaints against various investor-owned utilities, which included a
complaint against OE and Penn in the U.S. District Court for the Southern
District of Ohio. These cases are referred to as New Source Review cases. The
NOV and complaint allege violations of the Clean Air Act based on operation and
maintenance of the W. H. Sammis Plant dating back to 1984. The complaint
requests permanent injunctive relief to require the installation of best
available control technology and civil penalties of up to $27,500 per day of
violation. On August 7, 2003, the United States District Court for the Southern
District of Ohio ruled that 11 projects undertaken at the W. H. Sammis Plant
between 1984 and 1998 required pre-construction permits under the Clean Air
Act. The ruling concludes the liability phase of the case, which deals with
applicability of Prevention of Significant Deterioration provisions of the
Clean Air Act. The remedy phase trial to address civil penalties and what, if
any, actions should be taken to further reduce emissions at the plant has been
rescheduled to January 2005 by the Court because the parties are engaged in
meaningful settlement negotiations. The Court indicated, in its August 2003
ruling, that the remedies it may consider and impose involved a much broader,
equitable analysis, requiring the Court to consider air quality, public health,
economic impact, and employment consequences. The Court may also consider the
less than consistent efforts of the EPA to apply and further enforce the Clean
Air Act. The potential penalties that may be imposed, as well as the capital
expenditures necessary to comply with substantive remedial measures that may be
required, could have a material adverse impact on FirstEnergys, OEs and
Penns respective financial condition and results of operations. While the
parties are engaged in meaningful settlement discussions, management is unable
to predict the ultimate outcome of this matter and no liability has been
accrued as of September 30, 2004. Regulation of Hazardous Waste As a result of the Resource Conservation and Recovery Act of 1976, as
amended, and the Toxic Substances Control Act of 1976, federal and state
hazardous waste regulations have been promulgated. Certain fossil-fuel
combustion waste products, such as coal ash, were exempted from hazardous waste
disposal requirements pending the EPAs evaluation of the need for future
regulation. The EPA subsequently determined that regulation of coal ash as a
hazardous waste is unnecessary. In April 2000, the EPA announced that it will
develop national standards regulating disposal of coal ash under its authority
to regulate nonhazardous waste. The Companies have been named as PRPs at waste disposal sites which may
require cleanup under the Comprehensive Environmental Response, Compensation
and Liability Act of 1980. Allegations of disposal of hazardous substances at
historical sites and the liability involved are often unsubstantiated and
subject to dispute; however, federal law provides that all PRPs for a
particular site are liable on a joint and several basis. Therefore,
environmental liabilities that are considered probable have been recognized on
the Consolidated Balance Sheet as of September 30, 2004, based on estimates of
the total costs of cleanup, the Companies proportionate responsibility for
such costs and the financial ability of other nonaffiliated entities to pay. In
addition, JCP&L has accrued liabilities for environmental remediation of former
manufactured gas plants in New Jersey; those costs are being recovered by JCP&L
through a non-bypassable SBC. Included in Current Liabilities and Other
Noncurrent Liabilities are accrued liabilities aggregating approximately $65
million (JCP&L$45.8 million, CEI$2.4 million, TE$0.2 million,
Met-Ed$28,000, Penelec$26,000, and other$16.3 million) as of September 30,
2004. The Companies accrue environmental liabilities only when they can
conclude that it is probable that they have an obligation for such costs and
can reasonably determine the amount of such costs. Unasserted claims are
reflected in the Companies determination of environmental liabilities and are
accrued in the period that they are both probable and reasonably estimable. 11




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Climate Change In December 1997, delegates to the United Nations climate summit in Japan
adopted an agreement, the Kyoto Protocol (Protocol), to address global warming
by reducing the amount of man-made greenhouse gases emitted by developed
countries by 5.2% from 1990 levels between 2008 and 2012. The United States
signed the Protocol in 1998 but it failed to receive the two-thirds vote of the
U.S. Senate required for ratification. However, the Bush administration has
committed the United States to a voluntary climate change strategy to reduce
domestic greenhouse gas intensity  the ratio of emissions to economic output 
by 18% through 2012. The Companies cannot currently estimate the financial impact of climate
change policies, although the potential restrictions on CO2 emissions could
require significant capital and other expenditures. However, the CO2 emissions
per kilowatt-hour of electricity generated by the Companies is lower than many
regional competitors due to the Companies diversified generation sources which
includes low or non-CO2 emitting gas-fired and nuclear generators. Clean Water Act Various water quality regulations, the majority of which are the result of
the federal Clean Water Act and its amendments, apply to the Companies plants.
In addition, Ohio, New Jersey and Pennsylvania have water quality standards
applicable to the Companies operations. As provided in the Clean Water Act,
authority to grant federal National Pollutant Discharge Elimination System
water discharge permits can be assumed by a state. Ohio, New Jersey and
Pennsylvania have assumed such authority. On September 7, 2004, the EPA established new performance standards under
Clean Water Act Section 316(b) for reducing impacts on fish and shellfish from
cooling water intake structures at certain existing large electric generating
plants. The regulations call for reductions in impingement mortality, when
aquatic organisms are pinned against screens or other parts of a cooling water
intake system and entrainment, which occurs when aquatic species are drawn into
a facilitys cooling water system. The Companies are conducting comprehensive
demonstration studies, due in 2008, to determine the operational measures,
equipment or restoration activities, if any, necessary for compliance by their
facilities with the performance standards. FirstEnergy is unable to predict
the outcome of such studies. Depending on the outcome of such studies, the
future cost of compliance with these standards may be substantial. Power Outages and Related Litigation In July 1999, the Mid-Atlantic states experienced a severe heat wave which
resulted in power outages throughout the service territories of many electric
utilities, including JCP&Ls territory. In an investigation into the causes of
the outages and the reliability of the transmission and distribution systems of
all four New Jersey electric utilities, the NJBPU concluded that there was not
a prima facie case demonstrating that, overall, JCP&L provided unsafe,
inadequate or improper service to its customers. Two class action lawsuits
(subsequently consolidated into a single proceeding) were filed in New Jersey
Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking
compensatory and punitive damages arising from the July 1999 service
interruptions in the JCP&L territory. In August 2002, the trial court granted partial summary judgment to JCP&L
and dismissed the plaintiffs claims for consumer fraud, common law fraud,
negligent misrepresentation, and strict products liability. In November 2003,
the trial court granted JCP&Ls motion to decertify the class and denied
plaintiffs motion to permit into evidence their class-wide damage model
indicating damages in excess of $50 million. These class decertification and
damage rulings were appealed to the Appellate Division. The Appellate Court
issued a decision on July 8, 2004, affirming the decertification of the
originally certified class but remanding for certification of a class limited
to those customers directly impacted by the outages of transformers in Red
Bank, New Jersey. On September 8, 2004, the New Jersey Supreme Court denied
the motions filed by plaintiffs and JCP&L for leave to appeal the decision of
the Appellate Court. FirstEnergy is unable to predict the outcome of these
matters and no liability has been accrued as of September 30, 2004. On August 14, 2003, various states and parts of southern Canada
experienced widespread power outages. The outages affected approximately 1.4
million customers in FirstEnergys service area. On April 5, 2004, the U.S.
Canada Power System Outage Task Force released its final report on the
outages. In the final report, the Task Force concluded, among other things,
that the problems leading to the outages began in FirstEnergys Ohio service
area. Specifically, the final report concludes, among other things, that the
initiation of the August 14, 2003 power outages resulted from an alleged
failure of both FirstEnergy and ECAR to assess and understand perceived
inadequacies within the FirstEnergy system; inadequate situational awareness of
the developing conditions; and a perceived failure to adequately manage tree
growth in certain transmission rights of way. The Task Force also concluded
that there was a failure of the interconnected grids reliability organizations
(MISO and PJM) to provide effective diagnostic support. The final report is
publicly available through the Department of Energys website (www.doe.gov).
FirstEnergy believes that the final report does not provide a complete and
comprehensive picture of the conditions that contributed to the August 14, 2003
power outages and that it does not adequately address the underlying causes of
the outages. FirstEnergy remains convinced that the outages cannot be explained
by events on any one utilitys system. The final report contains 46 12




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recommendations to prevent or minimize the scope of future blackouts.
Forty-five of those recommendations relate to broad industry or policy matters
while one, including subparts, relates to activities the Task Force recommends
be undertaken by FirstEnergy, MISO, PJM, and ECAR. FirstEnergy implemented
several initiatives, both prior to and since the August 14, 2003 power outages,
which are consistent with these and other recommendations and collectively
enhance the reliability of its electric system. FirstEnergy certified to NERC
on June 30, 2004, completion of various reliability recommendations and further
received independent verification of completion status from a NERC verification
team on July 14, 2004 (see Regulatory Matters below). FirstEnergys
implementation of these recommendations included completion of the Task Force
recommendations that were directed toward FirstEnergy. As many of these
initiatives already were in process and budgeted in 2004, FirstEnergy does not
believe that any incremental expenses associated with additional initiatives
undertaken during 2004 will have a material effect on its operations or
financial results. FirstEnergy notes, however, that the applicable government
agencies and reliability coordinators may take a different view as to
recommended enhancements or may recommend additional enhancements in the future
that could require additional, material expenditures. FirstEnergy has not
accrued a liability as of September 30, 2004 for any expenditures in excess of
those actually incurred through that date. Three substantially similar actions were filed in various Ohio state
courts by plaintiffs seeking to represent customers who allegedly suffered
damages as a result of the August 14, 2003 power outages. All three cases were
dismissed for lack of jurisdiction. One case was refiled at the PUCO and the
other two have been appealed. In addition to the one case that was refiled at
the PUCO, the Ohio Companies were named as respondents in a regulatory
proceeding that was initiated at the PUCO in response to complaints alleging
failure to provide reasonable and adequate service stemming primarily from the
August 14, 2003 power outages. One complaint has been filed against FirstEnergy in the New York State
Supreme Court. In this case, several plaintiffs in the New York City
metropolitan area allege that they suffered damages as a result of the August
14, 2003 power outages. None of the plaintiffs are customers of any
FirstEnergy affiliate. FirstEnergy filed a motion to dismiss with the Court on
October 22, 2004. No damage estimate has been provided and thus potential
liability has not been determined. FirstEnergy is vigorously defending these actions, but cannot predict the
outcome of any of these proceedings or whether any further regulatory
proceedings or legal actions may be instituted against the Companies. In
particular, if FirstEnergy or its subsidiaries were ultimately determined to
have legal liability in connection with these proceedings, it could have a
material adverse effect on FirstEnergys or its subsidiaries financial
condition and results of operations. Nuclear Plant Matters FENOC received a subpoena in late 2003 from a grand jury sitting in the
United States District Court for the Northern District of Ohio, Eastern
Division requesting the production of certain documents and records relating to
the inspection and maintenance of the reactor vessel head at the Davis-Besse
plant. FirstEnergy is unable to predict the outcome of this investigation. In
addition, FENOC remains subject to possible civil enforcement action by the NRC
in connection with the events leading to the Davis-Besse outage in 2002.
Further, a petition was filed with the NRC on March 29, 2004 by a group
objecting to the NRCs restart order of the Davis-Besse Nuclear Power Station.
The Petition seeks, among other things, suspension of the Davis-Besse operating
license. A June 2, 2004 ASLB denial of the petition was appealed to the NRC.
FENOC and the NRC staff filed opposition briefs on June 24, 2004. If it were
ultimately determined that FirstEnergy or its subsidiaries has legal liability
or is otherwise made subject to enforcement action based on the Davis-Besse
outage, it could have a material adverse effect on FirstEnergys or its
subsidiaries financial condition and results of operations. On August 12, 2004, the NRC publicly disclosed that it was notifying
FirstEnergy that it will increase its regulatory oversight of the Perry Nuclear
Power Plant as a result of problems with safety system equipment over the past
two years. OE, CEI, TE and Penn own and/or lease the Perry Nuclear Power Plant.
The NRC noted that the plant continues to operate safely. The increased
oversight will include an extensive NRC team inspection to access the equipment
problems and FirstEnergys corrective actions. The outcome of this increased
oversight is not known at this time. Other Legal Matters Various lawsuits, claims (including claims for asbestos exposure) and
proceedings related to FirstEnergys normal business operations are pending
against FirstEnergy and its subsidiaries. The most significant not otherwise
discussed above are described below. On October 20, 2004, FirstEnergy was notified by the SEC that the
previously disclosed informal inquiry initiated by the SECs Division of
Enforcement in September 2003 relating to the restatements in August 2003 of
previously reported results by FirstEnergy and the Ohio Companies and the
Davis-Besse extended outage has become the subject of a formal order of
investigation. The SECs formal order of investigation also encompasses issues
raised 13




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during the SECs examination of FirstEnergy and the Companies under the PUHCA.
Concurrent with this notification, FirstEnergy received a subpoena asking for
background documents and documents related to the restatements and Davis-Besse
issues. FirstEnergy has cooperated fully with the informal inquiry and will
continue to do so with the formal investigation. Various legal proceedings alleging violations of federal securities laws
and related state laws were filed against FirstEnergy in connection with, among
other things, the restatements in August 2003 by FirstEnergy and the Ohio
Companies of previously reported results, the August 14, 2003 power outages
described above, and the extended outage at the Davis-Besse Nuclear Power
Station. The lawsuits were filed against FirstEnergy and certain of its
officers and directors. On July 27, 2004, FirstEnergy announced that it had
reached an agreement to resolve these pending lawsuits. The settlement
agreement, which does not constitute any admission of wrongdoing, provides for
a total settlement payment of $89.9 million. Of that amount, FirstEnergys
insurance carriers will pay $71.92 million, based on a contractual
pre-allocation, and FirstEnergy will pay $17.98 million, which resulted in an
after-tax charge against FirstEnergys second quarter and year-to-date 2004
earnings of $11 million or $0.03 per share of common stock (basic and diluted).
The settlement has been preliminarily approved by the court with a final
hearing scheduled for mid-December 2004. Although not anticipated to occur, in
the event that a significant number of shareholders do not accept the terms of
the settlement, FirstEnergy and individual defendants have the right, but not
the obligation, to set aside the settlement and recommence the litigation. On September 16, 2004, the FERC issued an order that imposed additional
obligations on CEI under certain pre-Open Access transmission contracts among
CEI and the cities of Cleveland and Painesville. Under the FERCs decision,
CEI may be responsible for a portion of new energy market charges imposed by
the MISO when its energy markets begin in the spring of 2005. CEI filed for
rehearing of the order from the FERC on October 18, 2004. The impact of the
FERC decision on CEI is dependent upon many factors, including the arrangements
made by the cities for transmission service, the startup date for the MISO
energy market, and the resolution of the rehearing request, and cannot be
determined at this time. If it were ultimately determined that FirstEnergy or its subsidiaries have
legal liability or are otherwise made subject to liability based on any of the
above matters, it could have a material adverse effect on FirstEnergys or its
subsidiaries financial condition and results of operations. 4  PENSION AND OTHER POSTRETIREMENT BENEFITS: The components of FirstEnergys net periodic pension cost, including
amounts capitalized, consisted of the following: Three Months Ended
    
    Nine Months EndedSeptember 30,
    
    September 30,Pension Benefits
    
    2004
    
    2003
    
    2004
    
    2003(In millions)Service cost
    
    $
    19
    
    
    $
    17
    
    
    $
    58
    
    
    $
    51Interest cost
    
    
    63
    
    
    
    65
    
    
    
    189
    
    
    
    194Expected return on plan assets
    
    
    (71
    )
    
    
    (64
    )
    
    
    (215
    )
    
    
    (191
    )Amortization of prior service cost
    
    
    2
    
    
    
    2
    
    
    
    7
    
    
    
    7Recognized net actuarial loss
    
    
    10
    
    
    
    16
    
    
    
    29
    
    
    
    48Net periodic cost
    
    $
    23
    
    
    $
    36
    
    
    $
    68
    
    
    $
    109
 In September 2004, FirstEnergy made a $500 million voluntary contribution
to its pension plan. Prior to this contribution, projections indicated that
cash contributions of approximately $600 million would have been required
during the 2006 to 2007 time period under minimum funding requirements
established by the IRS. The election to pre-fund the plan is expected to
eliminate that funding requirement. Since the contribution is deductible for
tax purposes, the after-tax cash impact of the voluntary contribution is
approximately $300 million. The payment was funded by FirstEnergys
subsidiaries through existing short-term credit arrangements, including
available intercompany money pools, as follows: (In millions)OE
    
    $
    60CEI
    
    
    32TE
    
    
    13Penn
    
    
    13JCP&L
    
    
    62Met-Ed
    
    
    39Penelec
    
    
    50All other subsidiaries
    
    
    231Total
    
    $
    500
 14




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##### Table of Contents



The components of FirstEnergys net periodic other postretirement benefit
cost, including amounts capitalized, consisted of the following: Three Months Ended
    
    Nine Months EndedSeptember 30,
    
    September 30,Other Postretirement Benefits
    
    2004
    
    2003
    
    2004
    
    2003(In millions)Service cost
    
    $
    9
    
    
    $
    16
    
    
    $
    27
    
    
    $
    49Interest cost
    
    
    26
    
    
    
    96
    
    
    
    83
    
    
    
    290Expected return on plan assets
    
    
    (10
    )
    
    
    (95
    )
    
    
    (32
    )
    
    
    (285
    )Amortization of prior service cost
    
    
    (9
    )
    
    
    4
    
    
    
    (28
    )
    
    
    11Recognized net actuarial loss
    
    
    9
    
    
    
    24
    
    
    
    29
    
    
    
    72Net periodic cost
    
    $
    25
    
    
    $
    45
    
    
    $
    79
    
    
    $
    137
 FirstEnergy contributed $17 million to its other postretirement benefit
plans in the nine months ended September 30, 2004. The Company has no funding
requirements for the remainder of 2004. Pension and postretirement benefit obligations are allocated to the
subsidiaries employing the plan participants. The Companies capitalize employee
benefits related to construction projects. The net periodic pension costs,
including amounts capitalized, recognized by each of the Companies in the three
and nine months ended September 30, 2004 and 2003 were as follows: Three Months Ended
    
    Nine Months EndedSeptember 30,
    
    September 30,Pension Benefit Cost
    
    2004
    
    2003
    
    2004
    
    2003(In millions)OE
    
    $
    1.7
    
    
    $
    6.3
    
    
    $
    5.2
    
    
    $
    12.1Penn
    
    
    0.1
    
    
    
    1.3
    
    
    
    0.4
    
    
    
    2.1CEI
    
    
    1.6
    
    
    
    2.7
    
    
    
    4.8
    
    
    
    6.9TE
    
    
    0.8
    
    
    
    1.4
    
    
    
    2.3
    
    
    
    3.5JCP&L
    
    
    1.9
    
    
    
    3.2
    
    
    
    5.6
    
    
    
    14.2Met-Ed
    
    
    0.1
    
    
    
    0.8
    
    
    
    0.2
    
    
    
    6.5Penelec
    
    
    0.1
    
    
    
    1.1
    
    
    
    0.4
    
    
    
    7.7
 The net periodic postretirement benefit costs, including amounts
capitalized, recognized by each of the Companies in the three and nine months
ended September 30, 2004 and 2003 were as follows: Three Months Ended
    
    Nine Months EndedSeptember 30,
    
    September 30,Other Postretirement Benefit Cost
    
    2004
    
    2003
    
    2004
    
    2003(In millions)OE
    
    $
    5.7
    
    
    $
    11.4
    
    
    $
    17.7
    
    
    $
    20.3Penn
    
    
    1.2
    
    
    
    2.2
    
    
    
    3.7
    
    
    
    3.5CEI
    
    
    4.4
    
    
    
    3.4
    
    
    
    13.7
    
    
    
    9.8TE
    
    
    1.7
    
    
    
    1.3
    
    
    
    5.0
    
    
    
    4.5JCP&L
    
    
    1.0
    
    
    
    3.7
    
    
    
    3.5
    
    
    
    16.2Met-Ed
    
    
    0.7
    
    
    
    2.2
    
    
    
    2.5
    
    
    
    8.7Penelec
    
    
    0.7
    
    
    
    2.4
    
    
    
    2.5
    
    
    
    8.9
 Pursuant to FSP 106-1 issued January 12, 2004, FirstEnergy began
accounting for the effects of the Medicare Act effective January 1, 2004
because of a plan amendment during the quarter, which required remeasurement of
the plans obligations. The plan amendment, which increases cost-sharing by
employees and retirees effective January 1, 2005, reduced postretirement
benefit costs during the three months and nine months ended September 30, 2004,
by $13 million and $35 million, respectively. Consistent with the guidance in FSP 106-2 issued May 19, 2004, FirstEnergy
recognized a reduction of $318 million in the accumulated postretirement
benefit obligation as a result of the federal subsidy provided under the
Medicare Act related to benefits for past service. The subsidy reduced net
periodic postretirement benefit costs during the three months and nine months
ended September 30, 2004, as follows: 15




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##### Table of Contents



Impact of federal subsidy provided
under the Medicare Act
    
    Three Months
    
    Nine Months(In millions)Service cost
    
    $
    (2
    )
    
    $
    (5
    )Interest cost
    
    
    (5
    )
    
    
    (15
    )Recognized net actuarial loss
    
    
    (5
    )
    
    
    (16
    )Decrease in net periodic cost
    
    $
    (12
    )
    
    $
    (36
    )
 The impact of the subsidy was not material to the financial statements of
each of the Companies for the three and nine months ended September 30, 2004. 5 - DIVESTITURES: FirstEnergy completed the sale of its international operations during the
quarter ended March 31, 2004 with the sales of its remaining 20.1% interest in
Avon on January 16, 2004, and its 28.67% interest in TEBSA on January 30, 2004.
Impairment charges related to Avon and TEBSA were recorded in the fourth
quarter of 2003 and no gain or loss was recognized upon the sales in 2004.
Avon, TEBSA and other international assets sold in 2003 were originally
acquired as part of FirstEnergys November 2001 merger with GPU. FirstEnergy completed the sale of its 50% interest in GLEP on June 23,
2004. Proceeds of $220 million included cash of $200 million and the right,
valued at $20 million, to participate for up to a 40% interest in future wells
in Ohio. This transaction produced an after-tax loss of $7 million, or $0.02
per share of common stock, including the benefits of prior tax capital losses
that had been previously fully reserved, which offset the capital gain from the
sale. 6 - REGULATORY MATTERS: In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry
deregulation contain similar provisions that are reflected in the Companies
respective state regulatory plans. These provisions include:  
    
    allowing the Companies electric customers to select their generation suppliers;
    
    establishing PLR obligations to non-shopping customers in the Companies service areas;
    
    allowing recovery of potentially stranded investment (or
transition costs) not otherwise recoverable in a competitive
generation market;
    
    itemizing (unbundling) the price of electricity into its
component elements  including generation, transmission,
distribution and stranded costs recovery charges;
    
    deregulating the Companies electric generation businesses;
    
    continuing regulation of the Companies transmission and distribution systems; and
    
    requiring corporate separation of regulated and unregulated business activities. However, despite these similarities, the specific approach taken by each
state and for each of the Companies varies. Reliability Initiatives On October 15, 2003, NERC issued a letter to all NERC control areas and
reliability coordinators requesting a review of various reliability practices.
The Company response confirmed that its review was completed and that various
enhancements were underway to current practices. On February 10, 2004, NERC
issued its Recommended Actions to Prevent and Mitigate the Impacts of Future
Cascading Blackouts, a portion of which were directed at the FirstEnergy
companies and broadly focused on initiatives that were recommended for
completion by June 30, 2004. FirstEnergys detailed implementation plan was
endorsed by the NERC Board of Trustees on May 7, 2004. The various initiatives
recommended by NERC were certified as complete by June 30, 2004, with one minor
exception related to reactive testing of certain generators expected to be
completed later in 2004. On February 26 and 27, 2004, certain FirstEnergy companies, as part of a
NERC review of control area operations throughout the United States,
participated in a NERC Control Area Readiness Audit. The final audit report,
completed on May 6, 2004, identified positive observations and included various
recommendations for reliability improvement. FirstEnergy reported completion of
those recommendations on June 30, 2004, with one exception related to MISOs
implementation of a voltage stability tool expected to be completed later this
year. 16




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##### Table of Contents



On April 5, 2004, the U.S. - Canada Power System Outage Task Force issued
a Final Report on the August 14, 2003 power outages. The Final Report contains
46 recommendations to prevent or minimize the scope of future blackouts.
Forty-five of those recommendations relate to broad industry or policy matters
while one, including subparts, relates to activities the Task Force recommended
be undertaken by FirstEnergy, MISO, PJM and ECAR. FirstEnergy completed the
Task Force recommendations that were directed toward FirstEnergy and reported
completion of those activities on June 30, 2004. With respect to each of the foregoing initiatives, FirstEnergy requested
and NERC provided, a technical assistance team of experts to provide ongoing
guidance and assistance in implementing and confirming timely and successful
completion. NERC further assembled an independent verification team to confirm
implementation of the foregoing initiatives required to be completed as of June
30, 2004. The NERC Verification Team reported, on July 14, 2004, that
FirstEnergy has completed the recommended policies, procedures and actions
required to be completed by June 30, 2004 or summer 2004, with exceptions noted
by FirstEnergy. Implementation of the recommendations has not required
incremental material investment or upgrades to existing equipment. On March 1, 2004, certain FirstEnergy companies filed, in accordance with
a November 25, 2003 order from the PUCO, their plan for addressing certain
issues identified by the PUCO from the U.S.  Canada Power System Outage Task
Force interim report. In particular, the filing addressed upgrades to
FirstEnergys control room computer hardware and software and enhancements to
the training of control room operators. The PUCO will review the plan before
determining the next steps, if any, in the proceeding. On April 22, 2004, FirstEnergy filed with the FERC the results of the
FERC-ordered independent study of part of Ohios power grid. The study
examined, among other things, the reliability of the transmission grid in
critical points in the Northern Ohio area and the need, if any, for reactive
power reinforcements during summers 2004 and 2009. Certain requested
additional clarifications were provided to the FERC in October 2004.
FirstEnergy completed the implementation of recommendations relating to 2004 by
June 30, 2004, and is continuing to review results related to 2009. The
estimated capital expenditures required by 2009 are not expected to have a
material adverse effect on FirstEnergys financial results. FirstEnergy notes,
however, that the FERC or other applicable government agencies and reliability
coordinators may take a different view as to recommended enhancements or may
recommend additional enhancements in the future that could require additional,
material expenditures. In late 2003, the PPUC issued a Tentative Order implementing new
reliability benchmarks and standards. In connection therewith, the PPUC
commenced a rulemaking procedure to amend the Electric Service Reliability
Regulations to implement these new benchmarks, and required additional
reporting on reliability. The PPUC ordered all Pennsylvania utilities to begin
filing quarterly reports on November 1, 2003. On May 11, 2004, the PPUC issued
an order approving the revised reliability benchmark and standards, including
revised benchmarks and standards for Met-Ed, Penelec and Penn. The Order
permitted Pennsylvania utilities to file in a separate proceeding to revise the
recomputed benchmarks and standards if they have evidence, such as the impact
of automated outage management systems, on the accuracy of the PPUC computed
reliability indices. Met-Ed, Penelec and Penn filed a Petition for Amendment of
Benchmarks with the PPUC on May 26, 2004 seeking amendment of the benchmarks
and standards due to their implementation of automated outage management
systems following restructuring. No procedural schedule or hearing date has
been set for this proceeding. FirstEnergy is unable to predict the outcome of
this proceeding. On January 16, 2004, the PPUC initiated a formal investigation of whether
Met-Eds, Penelecs and Penns service reliability performance deteriorated to
a point below the level of service reliability that existed prior to
restructuring in Pennsylvania. Hearings were held in early August 2004. On
September 30, 2004, Met-Ed, Penelec and Penn filed a settlement agreement with
the PPUC that addresses the issues related to this investigation. As part of
the settlement, Met-Ed, Penelec and Penn agreed to enhance service reliability,
performance reporting and communications with customers and to collectively
maintain their current spending levels of at least $255 million annually on
combined capital and operation and maintenance expenditures for transmission
and distribution for the years 2005 through 2007. In November 2004,
the PPUC accepted the recommendation of the ALJ approving the settlement. Ohio In July 1999, Ohios electric utility restructuring legislation, which
allowed Ohio electric customers to select their generation suppliers beginning
January 1, 2001, was signed into law. Among other things, the legislation
provided for a 5% reduction on the generation portion of residential customers
bills and the opportunity to recover transition costs, including regulatory
assets, from January 1, 2001 through December 31, 2005 (market development
period). The period for the recovery of regulatory assets only can be extended
up to December 31, 2010. The recovery period extension is related to the
customer shopping incentives recovery discussed below. The PUCO was authorized
to determine the level of transition cost recovery, as well as the recovery
period for the regulatory assets portion of those costs, in considering each
Ohio electric utilitys transition plan application. 17




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##### Table of Contents



In July 2000, the PUCO approved FirstEnergys transition plan for the Ohio
Companies as modified by a settlement agreement with major parties to the
transition plan. The application of SFAS 71 to OEs generation business and the
nonnuclear generation businesses of CEI and TE was discontinued with the
issuance of the PUCO transition plan order, as described further below. Major
provisions of the settlement agreement consisted of approval of recovery of
generation-related transition costs as filed of $4.0 billion net of deferred
income taxes (OE$1.6 billion, CEI$1.6 billion and TE$0.8 billion) and
transition costs related to regulatory assets as filed of $2.9 billion net of
deferred income taxes (OE$1.0 billion, CEI$1.4 billion and TE$0.5 billion),
with recovery through no later than 2006 for OE, mid-2007 for TE and 2008 for
CEI, except where a longer period of recovery is provided for in the settlement
agreement. The generation-related transition costs include $1.4 billion, net of
deferred income taxes, (OE$1.0 billion, CEI$0.2 billion and TE$0.2 billion)
of impaired generating assets recognized as regulatory assets as described
further below, $2.4 billion, net of deferred income taxes, (OE$1.2 billion,
CEI$0.4 billion and TE$0.8 billion) of above market operating lease costs and
$0.8 billion, net of deferred income taxes, (CEI$0.5 billion and TE$0.3
billion) of additional plant costs that were reflected on CEIs and TEs
regulatory financial statements. Also as part of the settlement agreement, FirstEnergy gives preferred
access over its subsidiaries to nonaffiliated marketers, brokers and
aggregators to 1,120 MW of generation capacity through 2005 at established
prices for sales to the Ohio Companies retail customers. Customer prices are
frozen through the five-year market development period, which runs through the
end of 2005, except for certain limited statutory exceptions, including the 5%
reduction referred to above. FirstEnergys Ohio customers choosing alternative suppliers receive an
additional incentive applied to the shopping credit (generation component) of
45% for residential customers, 30% for commercial customers and 15% for
industrial customers. The amount of the incentive is deferred for future
recovery from customers through an extension of the regulatory transition
charge. Under the modified Rate Stabilization Plan described below, the
deferred incentives and deferred interest costs related to the incentives will
be amortized on a dollar-for-dollar basis as the associated revenues are
recognized. On October 21, 2003, the Ohio Companies filed an application with the PUCO
to establish generation service rates beginning January 1, 2006, in response to
expressed concerns by the PUCO about price and supply uncertainty following the
end of the market development period. The filing included two options:  
    

    A competitive auction, which would establish a price for
generation that customers would be charged during the period
covered by the auction, or
    
    A Rate Stabilization Plan, which would extend current
generation prices through 2008, ensuring adequate generation supply
at stable prices, and continuing the Ohio Companies support of
energy efficiency and economic development efforts. Under that proposal, the Ohio Companies requested:  
    
    Extension of the transition cost amortization period for OE
from 2006 to 2007; for CEI from 2008 to 2009 and for TE from
mid-2007 to 2008;
    
    Deferral of interest costs on the accumulated shopping
incentives and other cost deferrals as new regulatory assets; and
    
    Ability to initiate a request to increase generation rates
under certain limited conditions. On February 23, 2004, after consideration of the PUCO Staff comments and
testimony as well as those provided by some of the intervening parties, the
Ohio Companies made certain modifications to the Rate Stabilization Plan. On
June 9, 2004, the PUCO issued an order approving the revised Rate Stabilization
Plan, subject to conducting a competitive bid process on or before December 1,
2004. In addition to requiring the competitive bid process, the PUCO made other
modifications to the Ohio Companies revised Rate Stabilization Plan
application. Among the major modifications were the following:  
    
    Limiting the ability of the Ohio Companies to request
adjustments in generation charges during 2006 through 2008 for
increases in taxes;
    
    Expanding the availability of market support generation;
    
    Revising the kilowatt-hour target level and the time period for recovering regulatory transition charges;
    
    Establishing a 3-year competitive bid process for generation; 18




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##### Table of Contents




    
    Establishing the 2005 generation credit for shopping
customers, which would be extended as a cap through 2008; and
    
    Denying the ability to defer costs for future recovery of
distribution reliability improvement expenditures. On June 18, 2004, the Ohio Companies filed with the PUCO an application
for rehearing of the modified version of the Rate Stabilization Plan. Several
other parties also filed applications for rehearing. On August 4, 2004, the
PUCO issued an Entry on Rehearing modifying its June 9, 2004 Order. The
modifications included the following:  
    
    Expanding the Ohio Companies ability to request
adjustments in generation charges during 2006 through 2008 to
include increases in the cost of fuel (including the cost of
emission allowances consumed, lime, stabilizers and other additives
and fuel disposal) using 2002 as the base year. Any increases in
fuel costs would be subject to downward adjustments in subsequent
years should fuel costs decline, but not below the generation rate
initially established in the Rate Stabilization Plan;
    
    Approving the revised kilowatt-hour target level and time
period for recovery of regulatory transition costs as presented by
the Ohio Companies in their rehearing application;
    
    Retaining the requirement for expanded availability of
market support generation, but adopting the Ohio Companies
alternative approach that conditions expanded availability on
higher pricing and eliminating the requirement to reduce the
interest deferral for certain affected rate schedules;
    
    Revising the calculation of the shopping credit cap for
certain commercial and small industrial rate schedules; and
    
    Relaxing the notice requirement for availability of
enhanced shopping credits in a number of instances. On August 5, 2004, the Ohio Companies accepted the Rate Stabilization Plan
as modified and approved by the PUCO on August 4, 2004. The Ohio Companies
retain the right to withdraw the modified Rate Stabilization Plan should
subsequent adverse action be taken by the PUCO or a court. In the second
quarter of 2004, the Ohio Companies implemented the accounting modifications
contained in the PUCOs June 9, 2004 Order, which are consistent with the
PUCOs August 4, 2004 Entry on Rehearing. Those modifications included
amortization of transition costs based on extended amortization periods (that
are no later than 2007 for OE, mid-2009 for CEI and mid-2008 for TE) and the
deferral of interest costs on the accumulated deferred shopping incentives. On
October 1, 2004, the OCC filed an appeal with the Ohio Supreme Court to
overturn the June 9, 2004 PUCO order. The Ohio Companies filed a proposed competitive bid process which the PUCO
modified on October 6, 2004. The PUCO approved the rules for the competitive
bid process setting a three-year supply period (2006-2008) requirement for
generation service suppliers and a load cap for individual suppliers. In
mid-October, the initial auction schedule was revised so that Part 1 and Part 2
auction bidder applications are due November 4, 2004 and November 15,
respectively, the trial auction is scheduled to occur on December 3, the
auction would commence December 8 and the PUCO will accept or reject auction
results within two business days after the completion of the auction.
FirstEnergy has elected to not participate in the auction. Transition Cost Amortization OE, CEI and TE amortize transition costs (see Regulatory Matters  Ohio)
using the effective interest method. Under the Rate Stabilization Plan as
approved above, total transition cost amortization is expected to approximate
the following for 2004 through 2009: FirstEnergy
    
    OE
    
    CEI
    
    TE(In millions)2004
    
    $
    754
    
    
    $
    429
    
    
    $
    200
    
    
    $
    1252005
    
    
    841
    
    
    
    475
    
    
    
    225
    
    
    
    1412006
    
    
    390
    
    
    
    182
    
    
    
    124
    
    
    
    842007
    
    
    315
    
    
    
    85
    
    
    
    141
    
    
    
    892008
    
    
    160
    
    
    
    
    
    
    
    160
    
    
    
    2009
    
    
    45
    
    
    
    
    
    
    
    45
    
    
    
    
 The Ohio Companies are deferring customer shopping incentives and interest
costs as new regulatory assets in accordance with the transition and rate
stabilization plans. These regulatory assets totaling $556 million as of
September 30, 2004 (OE - $205 million, CEI - $271 million, TE - $80 million)
will be recovered through a surcharge rate equal to the RTC rate in effect when
the transition costs have been fully recovered. Recovery of the new regulatory 19




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##### Table of Contents



assets will begin at that time and amortization of the regulatory assets for
each accounting period will be equal to the surcharge revenue recognized in
each period. New Jersey JCP&Ls 2001 Final Decision and Order (Final Order) with respect to its
rate unbundling, stranded cost and restructuring filings confirmed rate
reductions set forth in its 1999 Summary Order, which had been in effect at
increasing levels through July 2003. The Final Order also confirmed the
establishment of a non-bypassable SBC to recover costs which include nuclear
plant decommissioning and manufactured gas plant remediation, as well as a
non-bypassable MTC primarily to recover stranded costs. The NJBPU has deferred
making a final determination of the net proceeds and stranded costs related to
prior generating asset divestitures until JCP&Ls request for an IRS ruling
regarding the treatment of associated federal income tax benefits is acted
upon. Should the IRS ruling support the return of the tax benefits to
customers, there would be no effect to FirstEnergys or JCP&Ls net income
since the contingency existed prior to the merger and there would be an
adjustment to goodwill. In addition, the Final Order provided for the ability to securitize
stranded costs associated with the divested Oyster Creek Nuclear Generating
Station. Under NJBPU authorization in 2002, JCP&L issued through its wholly
owned subsidiary, JCP&L Transition, $320 million of transition bonds
(recognized as long-term debt on FirstEnergys and JCP&Ls Consolidated Balance
Sheets) which securitized the recovery of these costs and which provided for a
usage-based non-bypassable TBC to cover debt service on the bonds. Prior to August 1, 2003, JCP&Ls PLR obligation to provide BGS to
non-shopping customers was supplied almost entirely from contracted and open
market purchases. JCP&L is permitted to defer for future collection from
customers the amounts by which its costs of supplying BGS to non-shopping
customers and costs incurred under NUG agreements exceed amounts collected
through BGS and MTC rates. As of September 30, 2004, the accumulated deferred
cost balance totaled approximately $404 million, after the charge discussed
below. The NJBPU also allowed securitization of JCP&Ls deferred balance to the
extent permitted by law upon application by JCP&L and a determination by the
NJBPU that the conditions of the New Jersey restructuring legislation are met.
There can be no assurance as to the extent, if any, that the NJBPU will permit
such securitization. Under New Jersey transition legislation, all electric distribution
companies were required to file rate cases to determine the level of unbundled
rate components to become effective August 1, 2003. JCP&Ls two August 2002
rate filings requested increases in base electric rates of approximately $98
million annually and requested the recovery of deferred energy costs that
exceeded amounts being recovered under the current MTC and SBC rates; one
proposed method of recovery of these costs is the securitization of the
deferred balance. This securitization methodology is similar to the Oyster
Creek securitization. On July 25, 2003, the NJBPU announced its JCP&L base
electric rate proceeding decision, which reduced JCP&Ls annual revenues by
approximately $62 million effective August 1, 2003. The NJBPU decision also
provided for an interim return on equity of 9.5% on JCP&Ls rate base for the
subsequent six to twelve months. During that period, the decision also required
that, within approximately one year of its issuance, JCP&L would initiate
another proceeding to request recovery of additional costs incurred to enhance
system reliability. In that Phase II proceeding, the NJBPU could increase
JCP&Ls return on equity to 9.75% or decrease it to 9.25%, depending on its
assessment of the reliability of JCP&Ls service. Any reduction would be
retroactive to August 1, 2003. The net revenue decrease from the NJBPUs
decision consists of a $223 million decrease in the electricity delivery
charge, a $111 million increase due to the August 1, 2003 expiration of annual
customer credits previously mandated by the New Jersey transition legislation,
a $49 million increase in the MTC tariff component, and a net $1 million
increase in the SBC. The decision in the deferred balances proceeding
disallowed $153 million of deferred energy costs, so that the MTC allows for
the recovery of $465 million in deferred energy costs over the next ten years
on an interim basis. As a result, JCP&L recorded charges to net income for the
year ended December 31, 2003, aggregating $185 million ($109 million net of
tax) consisting of the $153 million of disallowed deferred energy costs and $32
million of other disallowed regulatory assets. JCP&L filed an interim motion
for rehearing and reconsideration with the NJBPU on August 15, 2003 with
respect to the following issues: (1) the disallowance of the $153 million
deferred energy costs; (2) the reduced rate of return on equity; and (3) $42.7
million of disallowed costs to achieve merger savings. In its final decision
and order issued on May 17, 2004, the NJPBU clarified the method for
calculating interest attributable to the cost disallowances, resulting in a
$5.4 million reduction from the amount estimated in 2003. On June 1, 2004,
JCP&L filed with the NJBPU a supplemental and amended motion for rehearing and
reconsideration. On July 7, 2004, the NJBPU granted limited reconsideration and
rehearing on the following issues: (1) deferred cost disallowances, (2) the
capital structure including the rate of return, (3) merger savings, including
amortization of costs to achieve merger savings; and (4) decommissioning. All
other issues included in JCP&Ls amended motion were denied. Oral arguments
were held on August 4, 2004. Management is unable to predict when a decision
may be reached by the NJBPU. On July 5, 2003, JCP&L experienced a series of 34.5 kilovolt
sub-transmission line faults that resulted in outages on the New Jersey shore.
The NJBPU instituted an investigation into these outages, and directed that a
Special Reliability Master (SRM) be hired to oversee the investigation. On
December 8, 2003, the SRM issued his Interim Report recommending that JCP&L
implement a series of actions to improve reliability in the area affected by
the outages. The 20




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##### Table of Contents



NJBPU adopted the findings and recommendations of the Interim Report on
December 17, 2003, and ordered JCP&L to implement the recommended actions on a
staggered basis, with initial actions to be completed by March 31, 2004. In
late 2003, in accordance with a Settlement Stipulation concerning an August
2002 storm outage, the NJBPU engaged Booth & Associates to conduct an audit of
the planning, operations and maintenance practices, policies and procedures of
JCP&L. The audit was expanded to include the July 2003 outage and was completed
in January 2004. On June 9, 2004, the NJBPU approved a stipulation that
incorporated the final SRM report and portions of the final Booth report. The
final order was issued by the NJBPU on July 23, 2004. On July 16, 2004, JCP&L filed the Phase II rate filing with the NJBPU
which requested an increase in base rates of $36 million, reflecting the
recovery of system reliability costs and a 9.75% return on equity. The filing
also requests an increase to the MTC deferred balance recovery of approximately
$20 million annually. Discovery/settlement conferences are ongoing. The filing
fulfills the NJBPU requirement that a Phase II proceeding be conducted and that
any expenditures and projects undertaken by JCP&L to increase its system
reliability be reviewed. JCP&L sells all self-supplied energy (NUGs and owned generation) to the
wholesale market with offsetting credits to its deferred energy balances with
the exception of 300 MW from JCP&Ls must run NUG committed supply currently
being used to serve BGS customers pursuant to NJBPU order. The BGS auction for
periods beginning June 1, 2004 was completed in February 2004 and new BGS
tariffs reflecting the auction results became effective June 1, 2004. On May
25, 2004, the NJBPU issued an order adopting a schedule for the BGS post
transition year three process. JCP&L filed its proposal suggesting how BGS
should be procured for year three and beyond. The NJBPU decision on the filing
was announced on October 22, 2004, approving with minor modifications the BGS
procurement process filed by JCP&L and the other New Jersey electric
distribution companies and authorizing the continued use of NUG committed
supply to serve 300 MW of BGS load. The auction is scheduled to take place in
February 2005 for the supply period beginning June 1, 2005. In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on
June 7, 2004 supporting a continuation of the current level and duration of the
funding of TMI-2 decommissioning costs by New Jersey ratepayers without a
reduction, termination or capping of the funding. On September 30, 2004, JCP&L
filed an updated TMI-2 decommissioning study prepared by TLG Services, Inc.
(see Note 2  Asset Retirement Obligations). This study resulted in an updated
total decommissioning cost estimate of $729 million (in 2003 dollars) compared
to the estimated $528 million (in 2003 dollars) from the prior 1995
decommissioning study. Pennsylvania The PPUC authorized in 1998 rate restructuring plans for Penn, Met-Ed and
Penelec. In 2000, the PPUC disallowed a portion of the requested additional
stranded costs above those amounts granted in Met-Eds and Penelecs 1998 rate
restructuring plan orders. The PPUC required Met-Ed and Penelec to seek an IRS
ruling regarding the return of certain unamortized investment tax credits and
excess deferred income tax benefits to customers. Similar to JCP&Ls situation,
if the IRS ruling ultimately supports returning these tax benefits to
customers, there would be no effect to FirstEnergys, Met-Eds or Penelecs net
income since the contingency existed prior to the merger and would be an
adjustment to goodwill. In June 2001, the PPUC approved the Settlement Stipulation with all of the
major parties in the combined merger and rate relief proceedings which approved
the FirstEnergy/GPU merger and provided PLR deferred accounting treatment for
energy costs, permitting Met-Ed and Penelec to defer, for future recovery,
energy costs in excess of amounts reflected in their capped generation rates
retroactive to January 1, 2001. This PLR deferral accounting procedure was
later denied in a February 2002 Commonwealth Court of Pennsylvania decision.
The court decision also affirmed the PPUC decision regarding approval of the
merger, remanding the decision to the PPUC only with respect to the issue of
merger savings. FirstEnergy established reserves in 2002 for Met-Eds and
Penelecs PLR deferred energy costs which aggregated $287.1 million, reflecting
the potential adverse impact of the then pending Pennsylvania Supreme Court
decision whether to review the Commonwealth Court decision. As a result,
FirstEnergy recorded in 2002 an aggregate non-cash charge of $55.8 million
($32.6 million net of tax) to income for the deferred costs incurred subsequent
to the merger. The reserve for the remaining $231.3 million of deferred costs
increased goodwill by an aggregate net of tax amount of $135.3 million. On April 2, 2003, the PPUC remanded the issue relating to merger savings
to the Office of Administrative Law for hearings, directed Met-Ed and Penelec
to file a position paper on the effect of the Commonwealth Court order on the
Settlement Stipulation and allowed other parties to file responses to the
position paper. Met-Ed and Penelec filed a letter with the ALJ on June 11,
2003, voiding the Settlement Stipulation in its entirety and reinstating
Met-Eds and Penelecs restructuring settlement previously approved by the
PPUC. On October 2, 2003, the PPUC issued an order concluding that the
Commonwealth Court reversed the PPUCs June 20, 2001 order in its entirety. The
PPUC directed Met-Ed and Penelec to file tariffs within thirty days of the
order to reflect the CTC rates and shopping credits that were in effect prior
to the June 21, 2001 order to be effective 21




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##### Table of Contents



upon one days notice. In response to that order, Met-Ed and Penelec filed
supplements to their tariffs to become effective October 24, 2003. On October 8, 2003, Met-Ed and Penelec filed a petition for clarification
relating to the October 2, 2003 order on two issues: to establish June 30, 2004
as the date to fully refund the NUG trust fund and to clarify that the ordered
accounting treatment regarding the CTC rate/shopping credit swap should follow
the ratemaking, and that the PPUCs findings would not impair their rights to
recover all of their stranded costs. On October 9, 2003, ARIPPA (an intervenor
in the proceedings) petitioned the PPUC to direct Met-Ed and Penelec to
reinstate accounting for the CTC rate/shopping credit swap retroactive to
January 1, 2002. Several other parties also filed petitions. On October 16,
2003, the PPUC issued a reconsideration order granting the date requested by
Met-Ed and Penelec for the NUG trust fund refund, denying Met-Eds and
Penelecs other clarification requests and granting ARIPPAs petition with
respect to the accounting treatment of the changes to the CTC rate/shopping
credit swap. On October 22, 2003, Met-Ed and Penelec filed an Objection with
the Commonwealth Court asking that the Court reverse the PPUCs finding that
requires Met-Ed and Penelec to treat the stipulated CTC rates that were in
effect from January 1, 2002 on a retroactive basis. On October 27, 2003, a Commonwealth Court judge issued an Order denying
Met-Eds and Penelecs Objection without explanation. Due to the vagueness of
the Order, Met-Ed and Penelec, on October 31, 2003, filed an Application for
Clarification with the judge. Concurrent with this filing, Met-Ed and Penelec,
in order to preserve their rights, also filed with the Commonwealth Court both
a Petition for Review of the PPUCs October 2 and October 16 Orders, and an
application for reargument, if the judge, in his clarification order, indicates
that Met-Eds and Penelecs Objection was intended to be denied on the merits.
In addition to these findings, Met-Ed and Penelec, in compliance with the
PPUCs Orders, filed revised PPUC quarterly reports for the twelve months ended
December 31, 2001 and 2002, and for the first two quarters of 2003, reflecting
balances consistent with the PPUCs findings in their Orders. Met-Ed and Penelec purchase a portion of their PLR requirements from FES
through a wholesale power sale agreement. The PLR sale is automatically
extended for each successive calendar year unless any party elects to cancel
the agreement by November 1 of the preceding year. Under the terms of the
wholesale agreement, FES retains the supply obligation and the supply profit
and loss risk, for the portion of power supply requirements not self-supplied
by Met-Ed and Penelec under their NUG contracts and other power contracts with
nonaffiliated third party suppliers. This arrangement reduces Met-Eds and
Penelecs exposure to high wholesale power prices by providing power at a fixed
price for their uncommitted PLR energy costs during the term of the agreement
with FES. FES has hedged most of Met-Eds and Penelecs unfilled PLR on-peak
obligation through 2004 and a portion of 2005, the period during which deferred
accounting was previously allowed under the PPUCs order. Met-Ed and Penelec
are authorized to continue deferring differences between NUG contract costs and
current market prices. 7 - NEW ACCOUNTING STANDARDS AND INTERPRETATIONS:  Exposure Draft of Proposed Statement of Financial Accounting Standards
Share-Based Payment an amendment of FASB Statements No. 123 and 95 In March 2004, the FASB issued an exposure draft of a new standard, which
would amend SFAS 123 and SFAS 95. Among other items, the new standard would
require expensing stock options in FirstEnergys financial statements. In
October 2004, the FASB agreed to delay the effective date of the proposed
standard from January 1, 2005 to periods beginning after June 15, 2005, for
calendar year companies. FirstEnergy will not be able to determine the impact
of the proposed standard on its results of operations until the standard is
issued in final form. The impacts of the fair value recognition provisions of
SFAS 123 on FirstEnergys net income and earnings per share for the current
reporting periods are disclosed in Note 2.  Exposure Draft of Proposed Statement of Financial Accounting Standards 
Earnings per Share  an amendment of FASB Statement No. 128 In December 2003, the FASB issued an exposure draft of a new standard,
which would amend SFAS 128. Among other items, the new standard would eliminate
the provisions of SFAS 128 that allow an entity to rebut the presumption that
contracts with the option of settling in either cash or stock will be settled
in stock. The new standard is expected to be issued in the fourth quarter of
2004 and be effective for all periods ending after December 15, 2004.
Retrospective application to all prior-period earnings per share data presented
would be required. FirstEnergy is continuing to assess the proposed standard
but does not anticipate a material impact on its calculation of earnings per
share. 22




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##### Table of Contents



EITF Issue No. 03-1, The Meaning of Other-Than-Temporary and Its
Application to Certain Investments In March 2004, the EITF reached a consensus on the application guidance
for Issue 03-1. EITF 03-1 provides a model for determining when investments in
certain debt and equity securities are considered other than temporarily
impaired. When an impairment is other-than-temporary, the investment must be
measured at fair value and the impairment loss recognized in earnings. The
recognition and measurement provisions of EITF 03-1, which were to be effective
for periods beginning after June 15, 2004, were delayed by the issuance of FSP
EITF 03-1-1 in September 2004. During the period of delay, FirstEnergy will
continue to evaluate its investments as required by existing authoritative
guidance.  EITF Issue No. 03-16, Accounting for Investments in Limited Liability
Companies In March 2004, the FASB ratified the final consensus on Issue 03-16. EITF
03-16 requires that an investment in a limited liability company that maintains
a specific ownership account for each investor should be viewed as similar to
an investment in a limited partnership for determining whether the cost or
equity method of accounting should be used. The equity method of accounting is
generally required for investments that represent more than a three to five
percent interest in a limited partnership. EITF 03-16 was adopted by
FirstEnergy in the third quarter of 2004 and did not affect the Companies
financial statements.  FSP 106-2, Accounting and Disclosure Requirements Related to the Medicare
Prescription Drug, Improvement and Modernization Act of 2003 Issued in May 2004, FSP 106-2 provides guidance on accounting for the
effects of the Medicare Act for employers that sponsor postretirement health
care plans that provide prescription drug benefits. FSP 106-2 also requires
certain disclosures regarding the effect of the federal subsidy provided by the
Medicare Act. The effect of the federal subsidy provided under the Medicare Act
on FirstEnergys consolidated financial statements is described in Note 4. The
impact of the subsidy was not material to the financial statements of each of
the Companies for the three and nine months ended September 30, 2004.  FIN 46 (revised December 2003), Consolidation of Variable Interest
Entities In December 2003, the FASB issued a revised interpretation of ARB 51
referred to as FIN 46R, which requires the consolidation of a VIE by an
enterprise if that enterprise is determined to be the primary beneficiary of
the VIE. As required, FirstEnergy adopted FIN 46R for interests in VIEs
commonly referred to as special-purpose entities effective December 31, 2003
and for all other types of entities effective March 31, 2004. Adoption of FIN
46R did not have a material impact on the consolidated financial statements of
FirstEnergy or the Companies. 8 - SEGMENT INFORMATION: FirstEnergy operates under two reportable segments: regulated services and
competitive services. The aggregate Other segments do not individually meet
the criteria to be considered a reportable segment. Other consists of
interest expense related to holding company debt; corporate support services
and the international businesses acquired in the 2001 merger. FirstEnergys
primary segment is its regulated services segment, whose operations include the
regulated sale of electricity and distribution and transmission services by its
eight EUOC in Ohio, Pennsylvania and New Jersey. The competitive services
business segment consists of the subsidiaries (FES, FSG, MYR and FirstCom) that
operate unregulated energy and energy-related businesses, including the
operation of FirstEnergys generation facilities resulting from the
deregulation of the Companies electric generation business (see Note 6 
Regulatory Matters). The regulated services segment designs, constructs,
operates and maintains FirstEnergys regulated transmission and distribution
systems. Its revenues are primarily derived from electricity delivery and
transition costs recovery. The competitive services segment has responsibility for FirstEnergy
generation operations as discussed under Note 6. As a result, its revenues
include all generation electric sales revenues (including the generation
services to regulated franchise customers who have not chosen an alternative
generation supplier) and all domestic unregulated energy and energy-related
services including commodity sales (both electricity and natural gas) in the
retail and wholesale markets, marketing, generation and sourcing of commodity
requirements, providing local and long-distance phone service, as well as other
competitive energy-application services. Segment reporting in 2003 was reclassified to conform with the current
year business segment organizations and operations. Revenues from the
competitive services segment now include all generation revenues including
generation services to regulated franchise customers previously reported under
the regulated services segment and now exclude revenues from power supply
agreements with the regulated services segment previously reported as internal
revenues. The regulated services segment results now exclude generation sales
revenues and related generation commodity costs. Certain amounts (including
transmission and congestion charges) were reclassified among purchased 23




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##### Table of Contents



power, other operating costs and depreciation and amortization to conform with
the current year presentation of generation commodity costs. Segment results
for 2003 have been adjusted to reflect the reclassification of revenue,
expense, interest expense and tax amounts of divested businesses reflected as
discontinued operations (see Note 2) and certain revenues and expenses have
been reclassified and presented on a net basis to conform with the current year
presentation (see Note 1). 24




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##### Table of Contents



Segment Financial Information Regulated
    
    Competitive
    
    
    
    
    
    ReconcilingServices
    
    Services
    
    Other
    
    Adjustments
    
    Consolidated(In millions)Three Months Ended:September 30, 2004External revenues
    
    $
    1,480
    
    
    $
    2,064
    
    
    $
    1
    
    
    $
    (9
    )(a)
    
    $
    3,536Internal revenues
    
    
    
    
    
    
    
    
    
    
    106
    
    
    
    (106
    )(b)
    
    
    Total revenues
    
    
    1,480
    
    
    
    2,064
    
    
    
    107
    
    
    
    (115
    )
    
    
    3,536Depreciation and amortization
    
    
    375
    
    
    
    9
    
    
    
    9
    
    
    
    
    
    
    
    393Net interest charges
    
    
    86
    
    
    
    10
    
    
    
    71
    
    
    
    (15
    )(b)
    
    
    152Income taxes
    
    
    225
    
    
    
    33
    
    
    
    (42
    )
    
    
    
    
    
    
    216Net income (loss)
    
    
    315
    
    
    
    47
    
    
    
    (63
    )
    
    
    
    
    
    
    299Total assets
    
    
    28,416
    
    
    
    2,168
    
    
    
    641
    
    
    
    
    
    
    
    31,225Total goodwill
    
    
    5,965
    
    
    
    136
    
    
    
    
    
    
    
    
    
    
    
    6,101Property additions
    
    
    157
    
    
    
    47
    
    
    
    7
    
    
    
    
    
    
    
    211September 30, 2003External revenues
    
    $
    1,478
    
    
    $
    1,929
    
    
    $
    18
    
    
    $
    (2
    )(a)
    
    $
    3,423Internal revenues
    
    
    
    
    
    
    
    
    
    
    136
    
    
    
    (136
    )(b)
    
    
    Total revenues
    
    
    1,478
    
    
    
    1,929
    
    
    
    154
    
    
    
    (138
    )
    
    
    3,423Depreciation and amortization
    
    
    370
    
    
    
    8
    
    
    
    11
    
    
    
    
    
    
    
    389Goodwill impairment
    
    
    
    
    
    
    117
    
    
    
    
    
    
    
    
    
    
    
    117Net interest charges
    
    
    116
    
    
    
    13
    
    
    
    54
    
    
    
    18
    (b)
    
    
    201Income taxes
    
    
    213
    
    
    
    (43
    )
    
    
    (35
    )
    
    
    
    
    
    
    135Income before discontinued operations and
cumulative effect of accounting change
    
    
    293
    
    
    
    (88
    )
    
    
    (53
    )
    
    
    
    
    
    
    152Net income (loss)
    
    
    293
    
    
    
    (86
    )
    
    
    (54
    )
    
    
    
    
    
    
    153Total assets
    
    
    29,794
    
    
    
    2,324
    
    
    
    1,377
    
    
    
    
    
    
    
    33,495Total goodwill
    
    
    5,993
    
    
    
    135
    
    
    
    
    
    
    
    
    
    
    
    6,128Property additions
    
    
    63
    
    
    
    88
    
    
    
    5
    
    
    
    
    
    
    
    156Nine Months Ended:September 30, 2004External revenues
    
    $
    4,047
    
    
    $
    5,808
    
    
    $
    13
    
    
    $
    1
    (a)
    
    $
    9,869Internal revenues
    
    
    
    
    
    
    
    
    
    
    354
    
    
    
    (354
    )(b)
    
    
    Total revenues
    
    
    4,047
    
    
    
    5,808
    
    
    
    367
    
    
    
    (353
    )
    
    
    9,869Depreciation and amortization
    
    
    1,099
    
    
    
    27
    
    
    
    29
    
    
    
    
    
    
    
    1,155Net interest charges
    
    
    301
    
    
    
    32
    
    
    
    213
    
    
    
    (43
    )(b)
    
    
    503Income taxes
    
    
    540
    
    
    
    69
    
    
    
    (99
    )
    
    
    
    
    
    
    510Net income (loss)
    
    
    760
    
    
    
    99
    
    
    
    (182
    )
    
    
    
    
    
    
    677Total assets
    
    
    28,416
    
    
    
    2,168
    
    
    
    641
    
    
    
    
    
    
    
    31,225Total goodwill
    
    
    5,965
    
    
    
    136
    
    
    
    
    
    
    
    
    
    
    
    6,101Property additions
    
    
    377
    
    
    
    152
    
    
    
    17
    
    
    
    
    
    
    
    546September 30, 2003External revenues
    
    $
    4,005
    
    
    $
    5,412
    
    
    $
    51
    
    
    $
    29
    (a)
    
    $
    9,497Internal revenues
    
    
    
    
    
    
    
    
    
    
    406
    
    
    
    (406
    )(b)
    
    
    Total revenues
    
    
    4,005
    
    
    
    5,412
    
    
    
    457
    
    
    
    (377
    )
    
    
    9,497Depreciation and amortization
    
    
    1,069
    
    
    
    22
    
    
    
    29
    
    
    
    
    
    
    
    1,120Goodwill impairment
    
    
    
    
    
    
    117
    
    
    
    
    
    
    
    
    
    
    
    117Net interest charges
    
    
    371
    
    
    
    37
    
    
    
    262
    
    
    
    (58
    )(b)
    
    
    612Income taxes
    
    
    550
    
    
    
    (207
    )
    
    
    (95
    )
    
    
    
    
    
    
    248Income before discontinued operations and
cumulative effect of accounting change
    
    
    754
    
    
    
    (321
    )
    
    
    (157
    )
    
    
    
    
    
    
    276Net income (loss)
    
    
    856
    
    
    
    (324
    )
    
    
    (219
    )
    
    
    
    
    
    
    313Total assets
    
    
    29,794
    
    
    
    2,324
    
    
    
    1,377
    
    
    
    
    
    
    
    33,495Total goodwill
    
    
    5,993
    
    
    
    135
    
    
    
    
    
    
    
    
    
    
    
    6,128Property additions
    
    
    218
    
    
    
    302
    
    
    
    60
    
    
    
    
    
    
    
    580
 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. 25




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##### Table of Contents



FIRSTENERGY CORP. 
 CONSOLIDATED STATEMENTS OF INCOME
(Unaudited) Three Months Ended
    
    Nine Months EndedSeptember 30,
    
    September 30,2004
    
    2003
    
    2004
    
    2003(In thousands, except per share amounts)REVENUES:Electric utilities
    
    $
    2,526,971
    
    
    $
    2,525,758
    
    
    $
    6,874,574
    
    
    $
    6,924,781Unregulated businesses
    
    
    1,009,348
    
    
    
    897,056
    
    
    
    2,994,092
    
    
    
    2,571,869Total revenues
    
    
    3,536,319
    
    
    
    3,422,814
    
    
    
    9,868,666
    
    
    
    9,496,650EXPENSES:Fuel and purchased power
    
    
    1,285,355
    
    
    
    1,199,408
    
    
    
    3,514,816
    
    
    
    3,338,361Purchased gas
    
    
    96,836
    
    
    
    105,213
    
    
    
    353,327
    
    
    
    453,824Other operating expenses
    
    
    917,345
    
    
    
    946,847
    
    
    
    2,641,870
    
    
    
    2,813,191Provision for depreciation and amortization
    
    
    393,218
    
    
    
    389,401
    
    
    
    1,154,895
    
    
    
    1,119,954Goodwill impairment (Note 2)
    
    
    
    
    
    
    116,988
    
    
    
    
    
    
    
    116,988General taxes
    
    
    177,452
    
    
    
    177,499
    
    
    
    514,269
    
    
    
    518,451Total expenses
    
    
    2,870,206
    
    
    
    2,935,356
    
    
    
    8,179,177
    
    
    
    8,360,769NET INTEREST CHARGES:Interest expense
    
    
    152,703
    
    
    
    199,106
    
    
    
    505,448
    
    
    
    598,645Capitalized interest
    
    
    (6,536
    )
    
    
    (6,513
    )
    
    
    (18,286
    )
    
    
    (23,287
    )Subsidiaries preferred stock dividends
    
    
    5,354
    
    
    
    8,021
    
    
    
    16,024
    
    
    
    36,423Net interest charges
    
    
    151,521
    
    
    
    200,614
    
    
    
    503,186
    
    
    
    611,781INCOME TAXES
    
    
    215,970
    
    
    
    135,151
    
    
    
    509,637
    
    
    
    247,692INCOME BEFORE DISCONTINUED OPERATIONS AND
CUMULATIVE EFFECT OF ACCOUNTING CHANGE
    
    
    298,622
    
    
    
    151,693
    
    
    
    676,666
    
    
    
    276,408Discontinued operations (net of income taxes (benefit) of
$(2,361,000) and $216,000 in the 2003 three month and
nine month periods, respectively) (Note 2)
    
    
    
    
    
    
    1,026
    
    
    
    
    
    
    
    (65,222
    )Cumulative effect of accounting change (net of income taxes
of $72,516,000) (Note 2)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    102,147NET INCOME
    
    $
    298,622
    
    
    $
    152,719
    
    
    $
    676,666
    
    
    $
    313,333BASIC EARNINGS PER SHARE OF COMMON STOCK:Income before discontinued operations and cumulative
effect of accounting change
    
    $
    0.91
    
    
    $
    0.51
    
    
    $
    2.07
    
    
    $
    0.93Discontinued operations (net of income taxes) (Note 2)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (0.22
    )Cumulative effect of accounting change (net of income taxes)
(Note 2)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    0.35Net income
    
    $
    0.91
    
    
    $
    0.51
    
    
    $
    2.07
    
    
    $
    1.06WEIGHTED AVERAGE NUMBER OF BASIC SHARES
OUTSTANDING
    
    
    327,499
    
    
    
    299,422
    
    
    
    327,280
    
    
    
    295,825DILUTED EARNINGS PER SHARE OF COMMON STOCK:Income before discontinued operations and cumulative
effect of accounting change
    
    $
    0.91
    
    
    $
    0.50
    
    
    $
    2.06
    
    
    $
    0.93Discontinued operations (net of income taxes) (Note 2)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (0.22
    )Cumulative effect of accounting change (net of income taxes)
(Note 2)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    0.34Net income
    
    $
    0.91
    
    
    $
    0.50
    
    
    $
    2.06
    
    
    $
    1.05WEIGHTED AVERAGE NUMBER OF DILUTED SHARES
OUTSTANDING
    
    
    329,099
    
    
    
    300,751
    
    
    
    328,850
    
    
    
    297,153DIVIDENDS DECLARED PER SHARE OF COMMON STOCK
    
    $
    0.375
    
    
    $
    0.375
    
    
    $
    1.125
    
    
    $
    1.125
 The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these statements. 26




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##### Table of Contents



FIRSTENERGY CORP. 
 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited) Three Months Ended
    
    Nine Months EndedSeptember 30,
    
    September 30,2004
    
    2003
    
    2004
    
    2003(In thousands)NET INCOME
    
    $
    298,622
    
    
    $
    152,719
    
    
    $
    676,666
    
    
    $
    313,333OTHER COMPREHENSIVE INCOME:Unrealized gain (loss) on derivative hedges
    
    
    5,927
    
    
    
    (8,133
    )
    
    
    26,536
    
    
    
    (6,594
    )Unrealized gain on available for sale securities
    
    
    8,715
    
    
    
    9,709
    
    
    
    5,265
    
    
    
    62,261Currency translation adjustments
    
    
    
    
    
    
    (11
    )
    
    
    
    
    
    
    91,450Other comprehensive income
    
    
    14,642
    
    
    
    1,565
    
    
    
    31,801
    
    
    
    147,117Income tax related to other comprehensive income
    
    
    (2,498
    )
    
    
    (41
    )
    
    
    (11,026
    )
    
    
    (23,529
    )Other comprehensive income, net of tax
    
    
    12,144
    
    
    
    1,524
    
    
    
    20,775
    
    
    
    123,588COMPREHENSIVE INCOME
    
    $
    310,766
    
    
    $
    154,243
    
    
    $
    697,441
    
    
    $
    436,921
 The preceding Notes to Consolidated Financial Statements as they relate to
FirstEnergy Corp. are an integral part of these statements. 27




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##### Table of Contents



FIRSTENERGY CORP. 
 CONSOLIDATED BALANCE SHEETS
(Unaudited) September 30,
    
    December 31,2004
    
    2003(In thousands)ASSETSCURRENT ASSETS:Cash and cash equivalents
    
    $
    67,892
    
    
    $
    113,975Receivables-Customers (less accumulated provisions of $48,031,000 and $50,247,000,
respectively, for uncollectible accounts)
    
    
    1,020,756
    
    
    
    1,000,259Other (less accumulated provisions of $28,392,000 and $12,851,000,
respectively, for uncollectible accounts)
    
    
    371,865
    
    
    
    505,241Materials and supplies, at average cost-Owned
    
    
    346,455
    
    
    
    325,303Under consignment
    
    
    95,728
    
    
    
    95,719Prepayments and other
    
    
    216,618
    
    
    
    202,8142,119,314
    
    
    
    2,243,311PROPERTY, PLANT AND EQUIPMENT:In service
    
    
    21,979,434
    
    
    
    21,594,746LessAccumulated provision for depreciation
    
    
    9,294,783
    
    
    
    9,105,30312,684,651
    
    
    
    12,489,443Construction work in progress
    
    
    653,718
    
    
    
    779,47913,338,369
    
    
    
    13,268,922INVESTMENTS:Nuclear plant decommissioning trusts
    
    
    1,461,893
    
    
    
    1,351,650Investments in lease obligation bonds
    
    
    966,685
    
    
    
    989,425Certificates of deposit
    
    
    
    
    
    
    277,763Other
    
    
    726,153
    
    
    
    878,8533,154,731
    
    
    
    3,497,691DEFERRED CHARGES:Regulatory assets
    
    
    5,792,517
    
    
    
    7,076,923Goodwill
    
    
    6,100,969
    
    
    
    6,127,883Other
    
    
    719,216
    
    
    
    695,21812,612,702
    
    
    
    13,900,024$
    31,225,116
    
    
    $
    32,909,948LIABILITIES AND CAPITALIZATIONCURRENT LIABILITIES:Currently payable long-term debt
    
    $
    674,901
    
    
    $
    1,754,197Short-term borrowings
    
    
    302,508
    
    
    
    521,540Accounts payable
    
    
    575,845
    
    
    
    725,239Accrued taxes
    
    
    969,622
    
    
    
    669,529Other
    
    
    959,475
    
    
    
    801,6623,482,351
    
    
    
    4,472,167CAPITALIZATION:Common stockholders equity-Common stock, $0.10 par value, authorized 375,000,000 shares-
329,836,276 shares outstanding
    
    
    32,984
    
    
    
    32,984Other paid-in capital
    
    
    7,055,997
    
    
    
    7,062,825Accumulated other comprehensive loss
    
    
    (331,874
    )
    
    
    (352,649
    )Retained earnings
    
    
    1,913,305
    
    
    
    1,604,385Unallocated employee stock ownership plan common stock-
2,246,960 and 2,896,951 shares, respectively
    
    
    (46,002
    )
    
    
    (58,204
    )Total common stockholders equity
    
    
    8,624,410
    
    
    
    8,289,341Preferred stock of consolidated subsidiaries not subject to mandatory redemption
    
    
    335,123
    
    
    
    335,123Long-term debt and other long-term obligations
    
    
    10,110,552
    
    
    
    9,789,06619,070,085
    
    
    
    18,413,530NONCURRENT LIABILITIES:Accumulated deferred income taxes
    
    
    2,019,446
    
    
    
    2,178,075Asset retirement obligations
    
    
    1,060,290
    
    
    
    1,179,493Power purchase contract loss liability
    
    
    2,173,888
    
    
    
    2,727,892Retirement benefits
    
    
    1,197,903
    
    
    
    1,591,006Lease market valuation liability
    
    
    957,450
    
    
    
    1,021,000Other
    
    
    1,263,703
    
    
    
    1,326,7858,672,680
    
    
    
    10,024,251COMMITMENTS, GUARANTEES AND CONTINGENCIES(Note 3)$
    31,225,116
    
    
    $
    32,909,948
 The preceding Notes to Consolidated Financial Statements as they relate to
FirstEnergy Corp. are an integral part of these balance sheets. 28




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##### Table of Contents



FIRSTENERGY CORP. 
 CONSOLIDATED STATEMENTS OF CASH FLOWS
 (Unaudited)
 Three Months Ended
    
    Nine Months EndedSeptember 30,
    
    September 30,2004
    
    2003
    
    2004
    
    2003(In thousands)CASH FLOWS FROM OPERATING ACTIVITIES:Net income
    
    $
    298,622
    
    
    $
    152,719
    
    
    $
    676,666
    
    
    $
    313,333Adjustments to reconcile net income to net cash from
operating activities-Provision for depreciation and amortization
    
    
    393,218
    
    
    
    389,401
    
    
    
    1,154,895
    
    
    
    1,119,954Nuclear fuel and lease amortization
    
    
    26,776
    
    
    
    16,902
    
    
    
    71,782
    
    
    
    47,398Other amortization, net
    
    
    (6,486
    )
    
    
    (9,540
    )
    
    
    (13,927
    )
    
    
    (6,244
    )Deferred costs recoverable as regulatory assets
    
    
    (118,409
    )
    
    
    (93,652
    )
    
    
    (263,290
    )
    
    
    (302,651
    )Deferred income taxes, net
    
    
    43,991
    
    
    
    (40,072
    )
    
    
    (37,206
    )
    
    
    (60,507
    )Investment tax credits, net
    
    
    (6,853
    )
    
    
    (7,349
    )
    
    
    (19,789
    )
    
    
    (19,855
    )Goodwill impairment
    
    
    
    
    
    
    116,988
    
    
    
    
    
    
    
    116,988Accrued retirement benefit obligations
    
    
    42,397
    
    
    
    81,819
    
    
    
    106,897
    
    
    
    229,172Accrued compensation, net
    
    
    26,592
    
    
    
    (440
    )
    
    
    48,186
    
    
    
    (70,976
    )Revenue credits to customers
    
    
    
    
    
    
    (19,583
    )
    
    
    
    
    
    
    (71,984
    )Disallowed regulatory assets
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    152,500Cumulative effect of accounting change
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (174,663
    )Loss (income) from discontinued operations
    
    
    
    
    
    
    (1,026
    )
    
    
    
    
    
    
    65,222Commodity derivative transactions, net
    
    
    17,336
    
    
    
    (34,939
    )
    
    
    (37,443
    )
    
    
    (31,137
    )Pension trust contribution
    
    
    (500,000
    )
    
    
    
    
    
    
    (500,000
    )
    
    
    Receivables
    
    
    16,288
    
    
    
    104,516
    
    
    
    187,730
    
    
    
    43,959Materials and supplies
    
    
    6,210
    
    
    
    19,708
    
    
    
    (21,161
    )
    
    
    (14,276
    )Prepayments and other current assets
    
    
    33,441
    
    
    
    109,687
    
    
    
    (16,172
    )
    
    
    (10,871
    )Accounts
payable
    
    
    (37,049
    )
    
    
    (136,271
    )
    
    
    (145,691
    )
    
    
    (171,314
    )Accrued taxes
    
    
    153,634
    
    
    
    188,261
    
    
    
    300,430
    
    
    
    210,115Accrued interest
    
    
    82,576
    
    
    
    68,357
    
    
    
    76,210
    
    
    
    51,898NUG power contract restructuring
    
    
    52,800
    
    
    
    
    
    
    
    52,800
    
    
    
    Deferred rents and lease market valuation liability
    
    
    28,402
    
    
    
    (6,401
    )
    
    
    (52,182
    )
    
    
    (86,363
    )Other
    
    
    11,929
    
    
    
    (20,475
    )
    
    
    (33,447
    )
    
    
    (24,765
    )Net cash provided from operating activities
    
    
    565,415
    
    
    
    878,610
    
    
    
    1,535,288
    
    
    
    1,304,933CASH FLOWS FROM FINANCING ACTIVITIES:New Financing-Common Stock
    
    
    
    
    
    
    934,605
    
    
    
    
    
    
    
    934,605Long-term debt
    
    
    86,754
    
    
    
    
    
    
    
    961,474
    
    
    
    771,637Redemptions and Repayments-Preferred stock
    
    
    (1,000
    )
    
    
    (1,000
    )
    
    
    (1,000
    )
    
    
    (126,337
    )Long-term debt
    
    
    (772,451
    )
    
    
    (569,273
    )
    
    
    (1,752,394
    )
    
    
    (1,337,205
    )Short-term borrowings, net
    
    
    228,072
    
    
    
    (798,985
    )
    
    
    (219,032
    )
    
    
    (846,734
    )Net controlled disbursement activity
    
    
    (19,129
    )
    
    
    (2,369
    )
    
    
    (36,400
    )
    
    
    31,352Common stock dividend payments
    
    
    (123,965
    )
    
    
    (110,373
    )
    
    
    (367,751
    )
    
    
    (330,816
    )Net cash used for financing activities
    
    
    (601,719
    )
    
    
    (547,395
    )
    
    
    (1,415,103
    )
    
    
    (903,498
    )CASH FLOWS FROM INVESTING ACTIVITIES:Property additions
    
    
    (211,243
    )
    
    
    (155,908
    )
    
    
    (545,743
    )
    
    
    (580,069
    )Nonutility generation trust withdrawals (contributions)
    
    
    
    
    
    
    
    
    
    
    (50,614
    )
    
    
    106,327Contribution to nuclear decommissioning trusts
    
    
    (25,370
    )
    
    
    (47,622
    )
    
    
    (76,112
    )
    
    
    (75,873
    )Proceeds from asset sales
    
    
    1,662
    
    
    
    1,081
    
    
    
    213,109
    
    
    
    67,530Proceeds from note receivable
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    19,000Cash investments
    
    
    (7,316
    )
    
    
    31,696
    
    
    
    19,640
    
    
    
    46,761Proceeds from certificates of deposit
    
    
    277,763
    
    
    
    
    
    
    
    277,763
    
    
    
    Other
    
    
    (30,838
    )
    
    
    (48,124
    )
    
    
    (4,311
    )
    
    
    28,851Net cash provided from (used for) investing activities
    
    
    4,658
    
    
    
    (218,877
    )
    
    
    (166,268
    )
    
    
    (387,473
    )Net increase (decrease) in cash and cash equivalents
    
    
    (31,646
    )
    
    
    112,338
    
    
    
    (46,083
    )
    
    
    13,962Cash and cash equivalents at beginning of period
    
    
    99,538
    
    
    
    127,556
    
    
    
    113,975
    
    
    
    225,932Cash and cash equivalents at end of period
    
    $
    67,892
    
    
    $
    239,894
    
    
    $
    67,892
    
    
    $
    239,894
 The preceding Notes to Consolidated Financial Statements as they relate to
FirstEnergy Corp. are an integral part of these statements. 29




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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 September 30, 2004, and the related
consolidated statements of income, comprehensive income and cash flows for each
of the three-month and nine-month periods ended September 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
November 2, 2004 30




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FIRSTENERGY CORP. 
 MANAGEMENTS DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION EXECUTIVE SUMMARY Net income in the third quarter of 2004 was $299 million, or basic and
diluted earnings of $0.91 per share of common stock, compared to net income of
$153 million, or basic earnings of $0.51 per share of common stock ($0.50
diluted) for the third quarter of 2003. FirstEnergys third quarter earnings
reflect solid progress  particularly in the areas of lower financing costs and
improvements in power generation and energy delivery operations. Net income in
the first nine months of 2004 was $677 million, or basic earnings of $2.07 per
share ($2.06 diluted), compared to $313 million, or basic earnings of $1.06 per
share ($1.05 diluted) for the first nine months of 2003. Earnings in the third
quarter and first nine 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 by $0.09 per share of
common stock (basic and diluted) in the third quarter of 2004 and reduced basic
and diluted earnings by $0.22 per share of common stock in the first nine
months of 2004. Milder weather during the third quarter of 2004 led to overall flat
kilowatt-hour deliveries compared with the year-prior quarter, including a
negative impact on residential customers because of lower air-conditioning use.
Despite the milder weather, FirstEnergys generation fleet continued to show
improved performance, enabling FirstEnergy to take advantage of additional spot
market sales. The fleet posted a record output in the third quarter and the
first nine months of 2004. FirstEnergys pension and other post-employment benefits expenses
decreased by $29 million in the third 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 effect from the new Medicare Act enacted
in December 2003. The same factors contributed to a $77 million decrease in
the first nine months of 2004, compared to the same period in 2003. FirstEnergys debt paydown and refinancing program reduced debt by $982
million during the first nine months of 2004 which is expected to produce
annualized savings of approximately $79 million. 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 August 5, 2004, the Ohio Companies accepted the Ohio 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. Those issues 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 its initial Rate Stabilization
Plan order. On October 1, 2004, the OCC filed an appeal with the Ohio Supreme
Court to overturn the June 9, 2004 PUCO order. The Ohio Companies filed a proposed competitive bid process which the PUCO
modified on October 6, 2004. The PUCO approved the rules for the competitive
bid process setting a three-year supply period (2006-2008) requirement for
generation service suppliers and a load cap for individual suppliers. In
mid-October, the initial auction schedule was revised so that Part 1 and Part 2
auction bidder applications are due November 4, 2004 and November 15,
respectively, the trial auction is scheduled to occur on December 3, the
auction commences December 8 and the PUCO will accept or reject auction results
within two business days after the completion of the auction. FirstEnergy has
elected to not participate in the auction. In September 2004, FirstEnergy and its subsidiaries made a $500 million
voluntary contribution to their pension plan to eliminate funding requirements
that were projected in 2006 and 2007. The net after-tax cost of the
contribution is approximately $300 million and is expected to be accretive to
earnings over the next three years. In addition, the contribution is expected
to reduce FirstEnergys overall risk profile, because it reduces uncertainty
regarding the plans unfunded liability. 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, by FirstEnergy and the Ohio Companies, the August 14, 2003
regional power outages and the extended outage at the Davis-Besse Nuclear Power
Station. The settlement agreement, which does not constitute an admission of
wrongdoing, provides for a total settlement payment of $89.9 million, of which 31




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FirstEnergys insurance carrier will pay $71.92 million. FirstEnergys portion
of $17.98 million, resulted in an after-tax charge of $11 million or $0.03 per
share of common stock (basic and diluted) in FirstEnergys second quarter and
year-to-date 2004 earnings. The settlement was preliminarily approved by the
court with a final hearing scheduled for mid-December 2004. FirstEnergy continues to participate in meaningful settlement negotiations
with the EPA and other parties to the New Source Review case involving the W.
H. Sammis Plant (see Outlook - Environmental Matters). As a result, the U.S.
District Court judge hearing the case rescheduled the date for the remedy phase
of the trial to January 2005. 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 continues
to evolve, FirstEnergy has taken and expects to take actions designed 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 subsidiary, 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 telephone 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 a competitive affiliate 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 and Penn are provided by FES. 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)  reflecting
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. 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. Business segment reporting in 2003 was reclassified
to conform with the current year business organizations and operations (see
Note 8). 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 and certain revenues and
expenses have been reclassified and presented on a net basis to conform with
the current year presentation. 32




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##### Table of Contents



RESULTS OF OPERATIONS The increase in net income of $146 million in the third quarter and $364
million in the first nine months of 2004 reflects higher income from continuing
operations of $147 million and $400 million, respectively, when current period
results are compared to those of 2003. A significant portion of the third
quarter and year-to-date improvement resulted from the absence of a goodwill
impairment charge recognized in 2003, lower energy delivery and nuclear
production costs and reduced interest expense. These positive factors were
offset in part by the impact of mild summer weather and losses recognized on
the sale of securities and impairment of several partnership investments. A
significant portion of the improvement in the first nine months of 2004 was the
absence of a $172 million charge incurred in 2003 for costs disallowed in the
JCP&L rate case decision of July 2003. The first nine months of 2003 also
included an after-tax charge of $67 million resulting from the abandonment of
FirstEnergys shares in Emdersas parent company, GPU Argentina Holdings, Inc.
and 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 nine months ended September 30, 2004 and
2003 are summarized in the table below. Three Months Ended
    
    Nine Months EndedSeptember 30,
    
    September 30,FirstEnergy
    
    2004
    
    2003
    
    2004
    
    2003(In millions)Total revenues
    
    $
    3,536
    
    
    $
    3,423
    
    
    $
    9,869
    
    
    $
    9,497Income before discontinued operations
and cumulative effect of accounting change
    
    
    299
    
    
    
    152
    
    
    
    677
    
    
    
    276Discontinued operations
    
    
    
    
    
    
    1
    
    
    
    
    
    
    
    (65
    )Cumulative effect of accounting change
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    102Net Income
    
    $
    299
    
    
    $
    153
    
    
    $
    677
    
    
    $
    313Basic Earnings Per Share:Income before discontinued operations and
cumulative effect of accounting change
    
    $
    0.91
    
    
    $
    0.51
    
    
    $
    2.07
    
    
    $
    0.93Discontinued operations
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (0.22
    )Cumulative effect of accounting change
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    0.35Net Income
    
    $
    0.91
    
    
    $
    0.51
    
    
    $
    2.07
    
    
    $
    1.06Diluted Earnings Per Share:Income before discontinued operations and
cumulative effect of accounting change
    
    $
    0.91
    
    
    $
    0.50
    
    
    $
    2.06
    
    
    $
    0.93Discontinued operations
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (0.22
    )Cumulative effect of accounting change
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    0.34Net Income
    
    $
    0.91
    
    
    $
    0.50
    
    
    $
    2.06
    
    
    $
    1.05
 Results of Operations  Third Quarter of 2004 Compared with the Third
Quarter of 2003 Total revenues increased $113 million in the third quarter of 2004. The
sources of changes in total revenues are summarized in the following table: Three Months EndedSeptember 30,
    
    IncreaseSources of Revenue Changes
    
    2004
    
    2003
    
    (Decrease)(In millions)Retail Electric Sales:EUOC-Wires
    
    $
    1,308
    
    
    $
    1,360
    
    
    $
    (52
    )-Generation
    
    
    909
    
    
    
    920
    
    
    
    (11
    )FES
    
    
    161
    
    
    
    173
    
    
    
    (12
    )Wholesale Electric Sales:EUOC
    
    
    137
    
    
    
    127
    
    
    
    10FES
    
    
    515
    
    
    
    383
    
    
    
    132Total Electric Sales
    
    
    3,030
    
    
    
    2,963
    
    
    
    67Transmission Revenues:Regulated services
    
    
    81
    
    
    
    10
    
    
    
    71Competitive services
    
    
    20
    
    
    
    16
    
    
    
    4Gas Sales
    
    
    101
    
    
    
    111
    
    
    
    (10
    )Other Revenues:EUOC
    
    
    92
    
    
    
    108
    
    
    
    (16
    )FES
    
    
    212
    
    
    
    197
    
    
    
    15International
    
    
    
    
    
    
    8
    
    
    
    (8
    )Miscellaneous
    
    
    
    
    
    
    10
    
    
    
    (10
    )Total Revenues
    
    $
    3,536
    
    
    $
    3,423
    
    
    $
    113
 33




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##### Table of Contents



Changes in electric generation kilowatt-hour sales and distribution
deliveries in the third quarter of 2004 are summarized in the following table: IncreaseChanges in KWH Sales
    
    (Decrease)Electric Generation Sales:Retail -EUOC
    
    
    (1.7
    )%FES
    
    
    (5.9
    )%Wholesale
    
    
    20.4
    %Total Electric Generation Sales
    
    
    5.0
    %EUOC Distribution Deliveries:Residential
    
    
    (2.1
    )%Commercial
    
    
    1.1
    %Industrial
    
    
    0.4
    %Total Distribution Deliveries
    
    
    (0.3
    )%
 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 $63 million decrease in retail
electric revenues from FirstEnergys EUOC in the third quarter of 2004. Sources of the Changes in EUOC Retail Electric RevenueIncrease (Decrease)
    
    (In millions)Changes in Customer Consumption:Alternative suppliers
    
    $
    (10
    )Economic, weather and other
    
    
    (20
    )(30
    )Changes in Price:Rate changes
    
    
    25Shopping incentives
    
    
    (14
    )Rate mix and other
    
    
    (44
    )(33
    )Net Decrease
    
    $
    (63
    )
 Reduced customer usage and lower rates contributed to a $63 million
decrease ($52 million of distribution deliveries and $11 million of generation)
in EUOC retail electric revenues in the third quarter of 2004, compared to the
third quarter of 2003. Lower usage due to cooler weather and alternative
energy suppliers providing a larger portion of franchise customer energy
requirements more than offset the effects of a stronger economy on demand.
Alternative energy suppliers provided 24.0% of the total energy delivered to
retail customers in the third quarter of 2004, compared to 22.9% in the same
period of 2003. Lower prices resulted from two factors  a shopping credit
rate increase in Ohio and a change in the mix of sales with a smaller
proportion of residential distribution deliveries (relative to commercial and
industrial deliveries) and fewer retail customers receiving generation in Ohio.
Partially offsetting the lower rates due to the changing mix of sales
primarily in Ohio were increased rates at JCP&L resulting from higher energy,
MTC and SBC rates; the increases in energy rates and MTC are concentrated in
the summer billing months. The increase in JCP&L energy, MTC and SBC rates were
moderated by lower base distribution rates due to the July 25, 2003, NJBPU base
electric rate proceeding decision (see Regulatory Matters  New Jersey)
effective August 1, 2003. Electric sales by FES increased by $120 million from additional sales to
the wholesale market which increased $132 million in the third quarter of 2004.
Higher electric sales to the wholesale market resulted in part from nuclear
generation increasing 45% (fossil generation decreased 8%), primarily as a
result of the Davis-Besse restart and fewer outages in 2004, which increased
total available generation by 8%. 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 September 30, 2004 and 2003 are
summarized as follows: 34




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##### Table of Contents



Three Months EndedSeptember 30,2004
    
    2003 (1)(In millions)Sales
    
    $
    366
    
    
    $
    264Purchases
    
    
    331
    
    
    
    269
  (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.
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 $75 million ($29 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 $3 million lower (excluding the GLEP partnership
interest) due to decreased volumes. 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. The generation margin in the third quarter of 2004 improved by $32 million
compared to the same period in 2003 and the ratio of generation margin to
revenue remained nearly unchanged. Higher electric generation sales resulted
principally from the additional sales in the wholesale market. The gas margin
increased $5 million despite lower sales volumes due to better unit margins on
sales to commercial and industrial customers. Three Months EndedSeptember 30,IncreaseEnergy Revenue Net of Commodity Costs
    
    2004
    
    2003
    
    (Decrease)(In millions)Electric generation revenue
    
    $
    1,721
    
    
    $
    1,603
    
    
    $
    118Fuel and purchased power
    
    
    1,285
    
    
    
    1,199
    
    
    
    86Generation Margin
    
    
    436
    
    
    
    404
    
    
    
    32Gas revenue(1)
    
    
    101
    
    
    
    104
    
    
    
    (3
    )Purchased gas
    
    
    97
    
    
    
    105
    
    
    
    (8
    )Gas Margin
    
    
    4
    
    
    
    (1
    )
    
    
    5Total Commodity Margins
    
    $
    440
    
    
    $
    403
    
    
    $
    37
  (1) Excludes GLEP partnership interest. Income before income taxes, discontinued operations and the cumulative
effect of an accounting change increased $228 million in the third 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:  
    
    Lower energy delivery expenses of $71 million reflecting
the absence in 2004 of significant storm restoration work and the
level of distribution reliability costs incurred in the third
quarter of 2003 and a higher level of construction activities in
2004 compared to more maintenance activities last year;  
    
    Lower nuclear production costs of $31 million primarily as
a result of no nuclear refueling outages in the third quarter of
2004 compared to a refueling outage at Beaver Valley Unit 2 ($28
million) during last years third quarter, and reduced incremental
maintenance costs at the Davis-Besse Plant ($16 million) related to
its restart;  
    
    Lower interest expense of $49 million due to debt and
preferred stock redemptions and refinancing activities and other
financing activities; and  
    
    Absence of the $117 million goodwill impairment charge recognized in the third quarter of 2003. Partially offsetting the above sources of improved earnings were two factors:  
    
    Reduced revenues of $52 million from distribution deliveries due to reduced rates and consumption; and 35




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##### Table of Contents




    
    A $28 million charge resulting from an impairment of equity
interests in several partnerships ($10 million) and losses
recognized on the sale of securities ($18 million). Discontinued Operations Net income in the third quarter of 2003 included $1 million of after-tax
earnings reflecting reclassification of revenues and expenses associated with
discontinued operations of FirstEnergys Bolivia business and FSG subsidiaries
- Colonial Mechanical, Webb Technologies and Ancoma, Inc. 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 $29 million in the third quarter of 2004. The following table
summarizes the net pension and OPEB expense for the three months ended
September 30, 2004 and 2003. Three Months EndedPostretirement Benefits Expense(1)
    
    September 30,2004
    
    2003(In millions)Pension
    
    $
    21
    
    
    $
    33OPEB
    
    
    22
    
    
    
    39Total
    
    $
    43
    
    
    $
    72
  (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 Nine Months of 2004 Compared with the First
Nine Months of 2003 Total revenues increased $372 million in the first nine months of 2004.
The sources of changes in total revenues are summarized in the following table: Nine Months EndedSeptember 30,Sources of Revenue Changes
    
    2004
    
    2003
    
    Increase
(Decrease)(In millions)Retail Electric Sales:EUOC-Wires
    
    $
    3,585
    
    
    $
    3,700
    
    
    $
    (115
    )-Generation
    
    
    2,440
    
    
    
    2,450
    
    
    
    (10
    )FES
    
    
    496
    
    
    
    416
    
    
    
    80Wholesale Electric Sales:EUOC
    
    
    387
    
    
    
    469
    
    
    
    (82
    )FES
    
    
    1,422
    
    
    
    926
    
    
    
    496Total Electric Sales
    
    
    8,330
    
    
    
    7,961
    
    
    
    369Transmission Revenues:EUOC
    
    
    211
    
    
    
    20
    
    
    
    191FES
    
    
    57
    
    
    
    36
    
    
    
    21Gas Sales
    
    
    380
    
    
    
    485
    
    
    
    (105
    )Other Revenues:EUOC
    
    
    251
    
    
    
    286
    
    
    
    (35
    )FES
    
    
    627
    
    
    
    659
    
    
    
    (32
    )International
    
    
    
    
    
    
    22
    
    
    
    (22
    )Miscellaneous
    
    
    13
    
    
    
    28
    
    
    
    (15
    )Total Revenues
    
    $
    9,869
    
    
    $
    9,497
    
    
    $
    372
 Changes in electric generation kilowatt-hour sales and distribution
deliveries in the first nine months of 2004 are summarized in the following
table: 36




---



##### Table of Contents



IncreaseChanges in KWH Sales
    
    (Decrease)Electric Generation Sales:Retail -EUOC
    
    
    (3.0
    )%FES
    
    
    9.1
    %Wholesale
    
    
    25.1
    %Total Electric Generation Sales
    
    
    6.8
    %EUOC Distribution Deliveries:Residential
    
    
    0.9
    %Commercial
    
    
    2.0
    %Industrial
    
    
    0.8
    %Total Distribution Deliveries
    
    
    1.2
    %
 The following major factors contributed to the $125 million reduction in
retail electric revenues from FirstEnergys EUOC in the first nine months of
2004. Sources of the Changes in EUOC Retail Electric RevenueIncrease (Decrease)
    
    (In millions)Changes in Customer Consumption:Alternative suppliers
    
    $
    (88
    )Economic, weather and other
    
    
    46(42
    )Changes in Price:Rate changes
    
    
    (16
    )Shopping incentives
    
    
    (40
    )Rate mix and other
    
    
    (27
    )(83
    )Net Decrease
    
    $
    (125
    )
 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 reducing
usage. Alternative suppliers provided 24.3% of the total energy delivered to
retail customers in the first nine months of 2004, compared to 21.1% in the
same period of 2003. A stronger economy only partially offset the combined
effects of mild summer weather in the third quarter of 2004, compared to the
same period of 2003, and reduced usage due to alternative energy suppliers
providing a larger portion of franchise customer energy requirements. Lower
prices resulted from three factors  a shopping credit rate increase in Ohio,
a change in the mix of sales with fewer retail customers receiving generation
in Ohio, and lower base distribution rates at JCP&L. Partially offsetting
JCP&Ls lower base distribution rates were higher energy, MTC and SBC rates;
the increases in energy rates and MTC are concentrated in the summer billing
months. EUOC sales to wholesale customers decreased by $82 million on a 20%
reduction in kilowatt-hour sales  JCP&Ls sales represented substantially all
of the decrease. Electric sales by FES increased by $576 million primarily from additional
spot sales in the wholesale market which increased $496 million for the first
nine months of 2004. Higher electric sales to the wholesale market were
possible due in part to a net 13% increase in generation, which was available
from the combination of an increase in FirstEnergys nuclear generating plants
(48% increase) offset in part by lower fossil generation (2% decrease). Retail
sales increased by $80 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 nine months ended September 30, 2004 and 2003 are
summarized as follows: 37




---



##### Table of Contents



Nine Months EndedSeptember 30,2004
    
    2003 (1)(In millions)Sales
    
    $
    1,114
    
    
    $
    794Purchases
    
    
    980
    
    
    
    833
 (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.
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 $212 million ($66 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 $99 million (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. Lower sales to large commercial and industrial customers in the first
nine months of 2004, compared to the same period in 2003, primarily reflected
fewer customers. The generation margin in the first nine months of 2004 improved by $307
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, the generation
margin increased $154 million and the ratio of generation margin to revenue
improved from 25.3% to 25.9%, reflecting additional lower-cost nuclear
generation. Higher electric generation sales resulted principally from the
additional sales to the wholesale market. The gas margin increased $2 million
from reduced costs. Nine Months EndedSeptember 30,
    
    IncreaseEnergy Revenue Net of Commodity Costs
    
    2004
    
    2003
    
    (Decrease)(In millions)Electric generation revenue
    
    $
    4,745
    
    
    $
    4,261
    
    
    $
    484Fuel and purchased power
    
    
    3,515
    
    
    
    3,338
    
    
    
    177Generation Margin
    
    
    1,230
    
    
    
    923
    
    
    
    307Gas revenue(1)
    
    
    368
    
    
    
    467
    
    
    
    (99
    )Purchased gas
    
    
    353
    
    
    
    454
    
    
    
    (101
    )Gas Margin
    
    
    15
    
    
    
    13
    
    
    
    2Total Commodity Margins
    
    $
    1,245
    
    
    $
    936
    
    
    $
    309
  (1) Excludes GLEP partnership interest. Income before income taxes, discontinued operations and the cumulative
effect of an accounting change increased $662 million in the first nine 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:  
    
    Lower energy delivery expenses of $58 million reflecting the
absence in 2004 of significant storm restoration work and the level
of distribution reliability costs incurred in the third quarter of
2003 and a higher level of construction activities in 2004 compared
to more maintenance activities last year;  
    
    Lower nuclear production costs of $181 million primarily as a
result of no nuclear refueling outages in the first nine months of
2004 compared to refueling outages at Beaver Valley Unit 1 ($47
million), Beaver Valley Unit 2 ($28 million) and the Perry Plant
($41 million) during the same period last year and reduced
incremental maintenance costs at the Davis-Besse Plant ($70 million)
related to its restart;  
    
    A net $58 million decrease in employee benefits expenses
primarily as a result of reduced postretirement benefit plan
expenses (see Postretirement Plans below), offset in part by
additional severance costs; 38




---



##### Table of Contents




    
    Absence of the $117 million goodwill impairment charge
recognized in the third quarter of 2003; and  
    
    Lower interest expense of $109 million due to debt and
preferred stock redemptions and refinancing activities. Partially offsetting the above sources of improved earnings were three
factors:  
    
    Reduced revenues of $115 million from distribution
deliveries due to reduced rates and consumption;  
    
    Charges for depreciation and amortization that increased
by $35 million due to an increase in amortization of regulatory
assets (offset in part by reduced depreciation rates resulting
from the JCP&L rate case); and  
    
    A $28 million charge resulting from an impairment of
equity interests in several partnerships ($10 million) and
losses recognized on the sale of securities ($18 million). Discontinued Operations Net income in the first nine months of 2003 included after-tax losses from
discontinued operations of $65 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 nine 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 $77 million in the first nine months of 2004. The following table
summarizes the net pension and OPEB expense for the nine months ended September
30, 2004 and 2003. Nine Months EndedSeptember 30,Postretirement Benefits Expense(1)
    
    2004
    
    2003(In millions)Pension
    
    $
    64
    
    
    $
    91OPEB
    
    
    68
    
    
    
    118Total
    
    $
    132
    
    
    $
    209
 (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. 39




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##### Table of Contents



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 the delivery of electricity
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 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:  
    
    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); and  
    
    The competitive services business segment consists of
the subsidiaries (FES, FSG, MYR and FirstCom) that principally
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
    
    Nine Months EndedNet Income (Loss)
    
    September 30,
    
    September 30,By Business Segment
    
    2004
    
    2003
    
    2004
    
    2003(In millions)Regulated services
    
    $
    315
    
    
    $
    293
    
    
    $
    760
    
    
    $
    856Competitive services
    
    
    47
    
    
    
    (86
    )
    
    
    99
    
    
    
    (324
    )Other(1)
    
    
    (63
    )
    
    
    (54
    )
    
    
    (182
    )
    
    
    (219
    )Total
    
    $
    299
    
    
    $
    153
    
    
    $
    677
    
    
    $
    313
  (1)
    
    Includes international operations and reflects an
after-tax charge of $67 million in
the nine months ended September 30, 2003 related to the
abandonment of FirstEnergys Argentina Business operations. Regulated Services  Third Quarter of 2004 Compared with the Third Quarter
of 2003 Financial results for the regulated services segment were as follows: Three Months EndedSeptember 30,Regulated Services
    
    2004
    
    2003
    
    Increase(In millions)Total revenues
    
    $
    1,480
    
    
    $
    1,478
    
    
    $
    2Net income
    
    
    315
    
    
    
    293
    
    
    
    22
 The change in operating revenues resulted from the following sources: Three Months EndedSeptember 30,IncreaseSources of Revenue Changes
    
    2004
    
    2003
    
    (Decrease)(In millions)Electric sales
    
    $
    1,308
    
    
    $
    1,360
    
    
    $
    (52
    )Other revenues
    
    
    172
    
    
    
    118
    
    
    
    54Total Revenues
    
    $
    1,480
    
    
    $
    1,478
    
    
    $
    2
 40




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##### Table of Contents

\

The net increase in operating revenues resulted from:  
    
    A decrease of $52 million in retail sales  a $37
million reduction in revenues from distribution deliveries
(wires and transition revenue) and a $15 million increase in the
credits for shopping incentives to customers; and  
    
    A net $54 million increase in other revenues due to
higher transmission revenues. Income before discontinued operations and the cumulative effect of an
accounting change increased $22 million in the third quarter of 2004 and
pre-tax income increased by $34 million from the following factors:  
    
    Lower energy delivery expenses of $71 million reflecting
the absence in 2004 of significant storm restoration work and the
level of distribution reliability costs incurred in the third
quarter of 2003 and a higher level of construction activities in
2004 compared to more maintenance activities last year;  
    
    A net margin increase from transmission-related
transactions of $30 million; and  
    
    Lower interest expense of $30 million due to debt and
preferred stock redemptions and refinancing activities. Partially offsetting the above sources of improved earnings were several
factors:  
    
    Reduced revenues of $52 million from distribution
deliveries resulting from reduced electricity deliveries and lower
prices;  
    
    An increase of $9 million in ancillary transmission service
refund expenses;  
    
    Decreases in other revenues of $10 million reflecting the
absence of income from certificates of deposit redeemed in June
2004 and lower JCP&L Transition TBC revenues; and  
    
    Charges for depreciation and amortization that increased $5
million due to additional amortization of regulatory assets (offset
in part by reduced depreciation rates resulting from the JCP&L rate
case). Competitive Services  Third Quarter of 2004 Compared with the Third
Quarter of 2003 Financial results for the competitive services segment were as follows: Three Months EndedSeptember 30,Competitive Services
    
    2004
    
    2003
    
    Increase(In millions)Total revenues
    
    $
    2,064
    
    
    $
    1,929
    
    
    $
    135Income (loss) before discontinued operations
    
    
    47
    
    
    
    (88
    )
    
    
    135Net income (loss)
    
    
    47
    
    
    
    (86
    )
    
    
    133
 The change in total revenues resulted from the following sources: Three Months EndedSeptember 30,IncreaseSources of Revenue Changes
    
    2004
    
    2003
    
    (Decrease)(In millions)Electric sales
    
    $
    1,722
    
    
    $
    1,603
    
    
    $
    119Natural gas sales
    
    
    101
    
    
    
    111
    
    
    
    (10
    )Energy-related sales
    
    
    211
    
    
    
    205
    
    
    
    6Other revenues
    
    
    30
    
    
    
    10
    
    
    
    20Total Revenues
    
    $
    2,064
    
    
    $
    1,929
    
    
    $
    135
 The net increase in electric sales resulted from:  
    
    Increased FES wholesale revenues of $132 million
(primarily spot sales) and higher EUOC sales to wholesale
customers of $10 million; and 41




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##### Table of Contents




    
    Lower retail generation sales through customer choice
programs ($12 million) and decreased generation sales to the
EUOC ($11 million). Natural gas sales were $10 million lower primarily due to the sale of GLEP
in June 2004. Excluding FirstEnergys interest in GLEP from 2003 results,
natural gas sales were $3 million lower due to decreased volumes. 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. The generation margin increased $32 million. Higher electric generation
revenues resulted from additional sales to the wholesale market which were
possible due to increased nuclear generation. The margin on gas sales
increased $5 million despite lower sales volumes due to better unit margins on
sales to commercial and industrial customers using lower supply costs
previously dedicated to the customer choice contracts. Income before discontinued operations and the cumulative effect of an
accounting change increased $135 million in the third quarter of 2004 and
pre-tax income increased by $211 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:  
    
    Lower nuclear production costs of $31 million primarily as
a result of no nuclear refueling outages in the third quarter of
2004 compared to a refueling outage at Beaver Valley Unit 2 ($28
million) during last years third quarter, and reduced incremental
maintenance costs at the Davis-Besse Plant ($16 million) related to
its restart;  
    
    Absence of the $117 million goodwill impairment charge
recognized in the third quarter of 2003; and  
    
    Reduced employee benefits expenses primarily as a result of
lower postretirement benefit plan expenses (see Postretirement
Plans above). Regulated Services  First Nine Months of 2004 Compared with the First
Nine Months of 2003 Financial results for the regulated services segment were as follows: Nine Months EndedSeptember 30,IncreaseRegulated Services
    
    2004
    
    2003
    
    (Decrease)(In millions)Total revenues
    
    $
    4,047
    
    
    $
    4,005
    
    
    $
    42Income before cumulative effect of accounting
change
    
    
    760
    
    
    
    754
    
    
    
    6Net income
    
    
    760
    
    
    
    856
    
    
    
    (96
    )
 The change in operating revenues resulted from the following sources: Nine Months EndedSeptember 30,IncreaseSources of Revenue Changes
    
    2004
    
    2003
    
    (Decrease)(In millions)Electric sales
    
    $
    3,585
    
    
    $
    3,700
    
    
    $
    (115
    )Other revenues
    
    
    462
    
    
    
    305
    
    
    
    157Total Revenues
    
    $
    4,047
    
    
    $
    4,005
    
    
    $
    42
 The increase in operating revenues resulted from:  
    
    A net decrease of $115 million in retail sales  a $94
million decrease in revenues from distribution deliveries and a
$21 million increase in shopping incentive credits to customers;
and  
    
    A net $157 million increase in other revenues primarily
due to higher transmission revenues. Income before discontinued operations and the cumulative effect of an
accounting change increased $6 million in the first nine months of 2004 and
pre-tax income decreased by $5 million. The following factors contributed to
the changes: 42




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##### Table of Contents




    
    Lower energy delivery expense of $58 million reflecting the
absence in 2004 of significant storm restoration work and the level
of distribution reliability costs incurred in the third quarter of
2003 and a higher level of construction activities in 2004 compared
to more maintenance activities last year;  
    
    A net contribution from transmission-related transactions
of $54 million; and  
    
    Lower interest expense of $70 million due to debt and
preferred stock redemptions and refinancing activities. Partially offsetting the above sources of improved earnings were two
factors:  
    
    Reduced revenues of $115 million from lower distribution
deliveries and prices; and  
    
    Increased charges for depreciation and amortization of $30
million due to an increase in amortization of regulatory assets
offset in part by reduced depreciation rates resulting from the
JCP&L rate case. Competitive Services  First Nine Months of 2004 Compared with the First
Nine Months of 2003 Financial results for the competitive services segment were as follows: Nine Months EndedSeptember 30,Competitive Services
    
    2004
    
    2003
    
    Increase(In millions)Total revenues
    
    $
    5,808
    
    
    $
    5,412
    
    
    $
    396Income (loss) before discontinued operations and
cumulative effect of accounting change
    
    
    99
    
    
    
    (321
    )
    
    
    420Net income (loss)
    
    
    99
    
    
    
    (324
    )
    
    
    423
 The change in total revenues resulted from the following sources: Nine Months EndedSeptember 30,IncreaseSources of Revenue Changes
    
    2004
    
    2003
    
    (Decrease)(In millions)Electric sales
    
    $
    4,745
    
    
    $
    4,261
    
    
    $
    484Natural gas sales
    
    
    380
    
    
    
    485
    
    
    
    (105
    )Energy-related sales
    
    
    601
    
    
    
    612
    
    
    
    (11
    )Other revenues
    
    
    82
    
    
    
    54
    
    
    
    28Total Revenues
    
    $
    5,808
    
    
    $
    5,412
    
    
    $
    396
 The increase in electric revenues resulted from:  
    
    Higher retail generation sales from customer choice
programs ($80 million) offset in part by lower generation sales
of the EUOC ($10 million); and  
    
    Increased wholesale revenues of $496 million from FES
(primarily spot sales) offset in part by an $82 million decrease
in EUOC sales to wholesale customers. Natural gas sales decreased $105 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 nine months of 2004 primarily reflected fewer customers. The generation margin increased $307 million as electric generation
revenues increased at a greater rate 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 $154 million. The
margin on gas sales increased $2 million on reduced sales. Income before discontinued operations and the cumulative effect of an
accounting change increased $420 million in the first nine months of 2004. In
addition to the effect of improved generation and gas margins discussed above,
the following factors contributed to that increase: 43




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##### Table of Contents




    
    Lower nuclear production costs of $181 million primarily as
a result of no nuclear refueling outages in the first nine months
of 2004 compared to refueling outages at Beaver Valley Unit 1 ($47
million), Beaver Valley Unit 2 ($28 million) and the Perry Plant
($41 million) during the same period last year and reduced
incremental maintenance costs at the Davis-Besse Plant ($70
million) related to its restart;  
    
    Absence of the $117 million goodwill impairment charge
recognized in the third quarter of 2003; and  
    
    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, ($1.214 billion unused as of
September 30, 2004). In the first nine months of 2004, FirstEnergy received
$515 million of cash dividends from its subsidiaries and paid $368 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 September 30, 2004, FirstEnergy had $68 million of cash and cash
equivalents, compared with $114 million as of December 31, 2003. The major
source of 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 third quarter and first nine months of 2004, compared with
the corresponding periods of 2003, were as follows: Three Months Ended
    
    Nine Months EndedSeptember 30,
    
    September 30,Operating Cash Flows
    
    2004
    
    2003
    
    2004
    
    2003(In millions)Cash earnings (1)
    
    $
    745
    
    
    $
    596
    
    
    $
    1,634
    
    
    $
    1,271Pension trust contribution
    
    
    (500
    )
    
    
    
    
    
    
    (500
    )
    
    
    Working capital and other
    
    
    320
    
    
    
    283
    
    
    
    401
    
    
    
    34Total
    
    $
    565
    
    
    $
    879
    
    
    $
    1,535
    
    
    $
    1,305
  (1)
    Includes net income, depreciation and amortization, deferred income taxes, investment tax credits and major noncash charges. Net cash provided from operating activities decreased $314 million in the
third quarter of 2004 compared to the same period last year due to a voluntary
pension trust contribution of $500 million in the third quarter of 2004. The
decrease was partially offset by a $149 million of increased cash earnings, as
described above under Results of Operations. During the first nine months of
2004, net cash provided from operating activities increased $230 million. The
increase in the first nine months of 2004 was due to a $367 million increase
from changes in working capital and $363 million of higher cash earnings,
partially offset by the $500 million pension trust contribution. The working
capital change primarily resulted from a $144 million decrease 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 $90 million
increase in accrued tax balances. 44




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##### Table of Contents



Cash Flows From Financing Activities The following table provides details regarding security issuances and
redemptions during the third quarter and first nine months of 2004 and 2003: Three Months Ended
    
    Nine Months EndedSeptember 30,
    
    September 30,Securities Issued or Redeemed
    
    2004
    
    2003
    
    2004
    
    2003(In millions)New IssuesCommon stock
    
    $
    
    
    
    $
    935
    
    
    $
    
    
    
    $
    935Pollution control notes
    
    
    77
    
    
    
    
    
    
    
    261
    
    
    
    Senior secured notes
    
    
    
    
    
    
    
    
    
    
    550
    
    
    
    400Long term revolving credit
    
    
    10
    
    
    
    
    
    
    
    
    
    
    
    40Unsecured notes
    
    
    
    
    
    
    
    
    
    
    150
    
    
    
    331$
    87
    
    
    $
    935
    
    
    $
    961
    
    
    $
    1,706RedemptionsFirst mortgage bonds
    
    $
    206
    
    
    $
    302
    
    
    $
    588
    
    
    $
    1,002Pollution control notes
    
    
    80
    
    
    
    4
    
    
    
    80
    
    
    
    54Senior secured notes
    
    
    374
    
    
    
    23
    
    
    
    447
    
    
    
    282Long-term revolving credit
    
    
    
    
    
    
    240
    
    
    
    300
    
    
    
    Unsecured notes
    
    
    112
    
    
    
    
    
    
    
    337
    
    
    
    Preferred stock
    
    
    1
    
    
    
    1
    
    
    
    1
    
    
    
    126$
    773
    
    
    $
    570
    
    
    $
    1,753
    
    
    $
    1,464Short-term Borrowings, Net
    
    $
    228
    
    
    $
    (799
    )
    
    $
    (219
    )
    
    $
    (847
    )
 Net cash used for financing activities increased by $54 million in the
third quarter of 2004 from the third quarter of 2003. The increase in cash used
for financing activities resulted primarily from an increase in net redemptions
and refinancings of debt and preferred securities and higher dividend payments.
Redemption and refinancing activities for debt and preferred stock aggregated
approximately $451 million during the third quarter of 2004 (including $25
million of pollution control note repricings). The redemption and refinancing
activities and pollution control note repricings are expected to result in
annualized savings of $47 million. Net cash used for the above financing
activities increased by $512 million in the first nine months of 2004 from the
same period of 2003. The increase in cash used for financing activities
resulted primarily from the absence of equity financing in 2004 and higher
dividend payments offset in part by the net issuance of debt. FirstEnergy has sinking fund requirements for preferred stock and maturing
long-term debt during the remainder of 2004, aggregating $23 million. These
cash requirements are expected to be satisfied from internal cash. FirstEnergy had approximately $303 million of short-term indebtedness as
of September 30, 2004 compared to approximately $522 million as of December 31,
2003. Unused borrowing capability as of September 30, 2004 included the
following: FirstEnergyUnused Borrowing Capability
    
    Holding Company
    
    OE
    
    Total(In millions)Long-Term Revolving Credit
    
    $
    1,375
    
    
    $
    375
    
    
    $
    1,750Utilized
    
    
    (10
    )
    
    
    
    
    
    
    (10
    )Letters of Credit
    
    
    (151
    )
    
    
    
    
    
    
    (151
    )Net
    
    
    1,214
    
    
    
    375
    
    
    
    1,589Short-Term Bank Facilities
    
    
    
    
    
    
    34
    
    
    
    34Utilized
    
    
    
    
    
    
    (20
    )
    
    
    (20
    )Net
    
    
    
    
    
    
    14
    
    
    
    14Total Unused Borrowing Capability
    
    $
    1,214
    
    
    $
    389
    
    
    $
    1,603
 As of September 30, 2004, the Ohio EUOC and Penn had the aggregate
capability to issue approximately $4.1 billion of additional FMBs on the basis
of property additions and retired bonds under the terms of their respective
mortgage indentures. The issuances of FMBs by OE and CEI are also subject to
provisions of their senior note indentures generally limiting the incurrence of
additional secured debt, subject to certain exceptions that would permit, among
other things, the issuance of secured debt (including FMBs) (i) supporting
pollution control notes or similar obligations, or (ii) as an extension,
renewal or replacement of previously outstanding secured debt. In addition,
these provisions would permit OE and CEI to incur additional secured debt not
otherwise permitted by a specified exception of up to $639 million and $582
million, respectively, as of September 30, 2004. Under the provisions of its
senior note indenture, JCP&L may issue additional FMBs only as collateral for
senior notes. As of September 30, 2004, JCP&L had 45




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##### Table of Contents



the capability to issue $490 million of additional senior notes upon the basis
of FM collateral. Based upon applicable earnings coverage tests in their
respective charters, OE, TE, Penn, and JCP&L could issue a total of $4.0
billion of preferred stock (assuming no additional debt was issued) as of
September 30, 2004. CEI, Met-Ed and Penelec have no restrictions on the
issuance of preferred stock. FirstEnergys working capital and short-term borrowing needs are met
principally with a syndicated $1 billion three-year revolving credit facility
maturing in June 2007. Combined with a 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 a syndicated $250 million
two-year facility for OE maturing in May 2005, FirstEnergys primary syndicated
credit facilities total $1.75 billion. These revolving credit 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 $1.7 billion as
of September 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 September 30, 2004, FirstEnergys and
OEs fixed charge coverage ratios, as defined under the credit agreements, were
4.08 to 1 and 7.36 to 1, respectively. FirstEnergys and OEs debt to total
capitalization ratios, as defined under the credit agreements, were 0.55 to 1
and 0.39 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 FirstEnergy to meet their short-term working capital requirements. A
similar but separate arrangement exists among its competitive 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 third quarter of 2004 was 1.28% for the regulated companies pool and 1.32%
for the competitive companies pool. On September 1, 2004, Penelec redeemed at par $100 million principal
amount of its subordinated debentures in connection with the concurrent
redemption at par of $100 million principal amount of Penelec Capital Trust
7.34% Trust Preferred Securities. 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-. On August 26, 2004, S&P lowered its rating on certain Met-Ed Senior Notes
to BBB- from BBB. The rationale for the ratings change was that Met-Eds
senior secured notes, in aggregate, now comprise greater than 80% of Met-Eds
total debt outstanding. According to the terms of the senior note indenture,
once the 80% threshold is reached, the collateral mortgage bond security falls
away and all senior secured notes that were secured by Met-Eds senior note
indenture become unsecured. The one notch lower rating reflects this loss of
collateral security. The BBB senior secured rating on Met-Eds first mortgage
bonds remain unchanged. Also on August 26, 2004, S&P stated that a favorable outcome of the Ohio
Rate Stabilization Plan auction process and a favorable resolution of pending
environmental litigation would support a higher ratings outlook, or possibly a
higher rating. S&P noted that a ratings upgrade in 2004 does not appear likely
because those major issues would most likely not be resolved before the end of
2004. On September 14, 2004, S&P stated that FirstEnergys $500 million
voluntary contribution to its pension plan was credit neutral. 46




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##### Table of Contents



Cash Flows From Investing Activities Net cash flows provided from investing activities totaled $5 million in
the third quarter of 2004, compared to net cash flows used of $219 million for
investing activities for the same period of 2003. The $224 million change
resulted from $278 million in cash proceeds from certificates of deposit in the
third quarter of 2004. The following table summarizes investments by FirstEnergys regulated
services and competitive services segments in the third quarter and first nine
months of 2004: Summary of Cash Used
    
    Propertyfor Investing Activities
    
    Additions
    
    Investments
    
    Other
    
    TotalSources (Uses)
    
    
    
    
    
    (In millions)Three Months Ended September 30, 2004Regulated Services
    
    $
    (157
    )
    
    $
    246
    (1)
    
    $
    (68
    )
    
    $
    21Competitive Services
    
    
    (47
    )
    
    
    (10
    )
    
    
    (2
    )
    
    
    (59
    )Other
    
    
    (7
    )
    
    
    (33
    )
    
    
    83
    
    
    
    43Total
    
    $
    (211
    )
    
    $
    203
    
    
    $
    13
    
    
    $
    5Nine Months Ended September 30, 2004Regulated Services
    
    $
    (377
    )
    
    $
    181
    (1)(2)
    
    $
    (75
    )
    
    $
    (271
    )Competitive Services
    
    
    (152
    )
    
    
    188
    (3)
    
    
    2
    
    
    
38Other
    
    
    (17
    )
    
    
    20
    
    
    
    64
    
    
    
    67Total
    
    $
    (546
    )
    
    $
    389
    
    
    $
    (9
    )
    
    $
    (166
    )
  (1)
    Includes $278 million in cash proceeds from certificates of
deposit.  (2)
    Includes $51 million refunding payment to a NUG trust fund.  (3)
    Includes $200 million in cash proceeds from the sale of GLEP. In the last quarter of 2004, capital requirements for property additions
and capital leases are expected to be approximately $293 million, including $75
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 $717 million is applicable to 2004. Investments for additional
nuclear fuel during the 2004-2006 period are estimated to be approximately $303
million, of which approximately $90 million applies to 2004. During the same
periods, the Companies nuclear fuel investments are expected to be reduced by
approximately $269 million and $88 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 September 30, 2004, the maximum potential future payments under
outstanding guarantees and other assurances totaled approximately $2.1 billion
as summarized below: 47




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##### Table of Contents



MaximumGuarantees and Other Assurances
    
    Exposure(In millions)FirstEnergy Guarantees of Subsidiaries:Energy and Energy-Related Contracts (1)
    
    $
    862Other (2)
    
    
    1491,011Surety Bonds
    
    
    280Letters of Credit (3)(4)
    
    
    815Total Guarantees and Other Assurances
    
    $
    2,106
  (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
$151 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 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 is remote that such parental
guarantees will increase amounts otherwise paid by FirstEnergy to meet its
obligations incurred in connection with ongoing energy-related activities. 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 September 30, 2004: Collateral PaidTotal
    
    
    
    
    
    
    
    
    
    RemainingCollateral Provisions
    
    Exposure (1)
    
    Cash
    
    Letters of Credit
    
    Exposure(In millions)Rating downgrade
    
    $
    358
    
    
    $
    145
    
    
    $
    18
    
    
    $
    195Adverse event
    
    
    113
    
    
    
    
    
    
    
    23
    
    
    
    90Total
    
    $
    471
    
    
    $
    145
    
    
    $
    41
    
    
    $
    285
  (1)
    As of October 12, 2004, FirstEnergys total
exposure decreased to $465 million and the remaining
exposure decreased to $272 million  net of $152
million of cash collateral and $41 million of LOC
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 LOCs totaling approximately $237 million (as
described above) during the second quarter of 2004. In connection with the sale of the TEBSA project in Colombia in January
2004, FirstEnergy guaranteed the
obligations of the operators of the project, up to a maximum of $6 million
(subject to escalation) under the projects 48




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##### Table of Contents



operation and maintenance agreement
for so long as such obligations exist. The purchaser of TEBSA agreed to
indemnify FirstEnergy against any loss under this guarantee. Also in connection
with the TEBSA project, FirstEnergy has provided the TEBSA project lenders with
a $60 million LOC and a $400,000 LOC. The $60 million LOC was established as a
substitute asset for FirstEnergys interest in its Midlands companies pursuant
to an indemnity agreement in favor of the TEBSA project lenders. As of October
15, 2004, the value of the LOC decreased to $46 million. The balance will
continue to decline annually and will be fully discharged and released in
October 2010. The substitute LOC enabled FirstEnergy to sell its remaining
20.1% interest in Avon (parent of Midlands Electricity in the United Kingdom).
The $400,000 LOC was established to secure the TEBSA project lenders in the
event that liquidated shares of TEBSA were unable to be converted into U.S.
currency. The $400,000 LOC will terminate upon the registration of certain of
TEBSAs stock with the Colombian Central Bank. 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 September 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 $199
million of off-balance sheet financing as of September 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
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 third quarter and first nine months of 2004 is
summarized in the following table: 49




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##### Table of Contents



Increase (Decrease) in the Fair Value
Of Commodity Derivative Contracts Three Months Ended
    
    Nine Months EndedSeptember 30, 2004
    
    September 30, 2004Non-Hedge
    
    Hedge
    
    Total
    
    Non-Hedge
    
    Hedge
    
    Total(In millions)Change in the Fair Value of Commodity
Derivative Contracts:Outstanding net asset at beginning of period
    
    $
    62
    
    
    $
    8
    
    
    $
    70
    
    
    $
    67
    
    
    $
    12
    
    
    $
    79New contract value when entered
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Additions/change in value of existing contracts
    
    
    
    
    
    
    3
    
    
    
    3
    
    
    
    (5
    )
    
    
    11
    
    
    
    6Change in techniques/assumptions
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Settled contracts
    
    
    1
    
    
    
    (4
    )
    
    
    (3
    )
    
    
    1
    
    
    
    (16
    )
    
    
    (15
    )Outstanding net asset at end of period (1)
    
    
    63
    
    
    
    7
    
    
    
    70
    
    
    
    63
    
    
    
    7
    
    
    
    70Non-commodity Net Assets at End of Period:Interest Rate Swaps (2)
    
    
    
    
    
    
    27
    
    
    
    27
    
    
    
    
    
    
    
    27
    
    
    
    27Net Assets  Derivative Contracts at End of Period
    
    $
    63
    
    
    $
    34
    
    
    $
    97
    
    
    $
    63
    
    
    $
    34
    
    
    $
    97Impact of Changes in Commodity Derivative
Contracts (3)Income Statement Effects (Pre-Tax)
    
    $
    1
    
    
    $
    
    
    
    $
    1
    
    
    $
    (3
    )
    
    $
    
    
    
    $
    (3
    )Balance Sheet Effects:Other Comprehensive Income (Pre-Tax)
    
    $
    
    
    
    $
    (1
    )
    
    $
    (1
    )
    
    $
    
    
    
    $
    (5
    )
    
    $
    (5
    )Regulatory Liability
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    (1
    )
    
    $
    
    
    
    $
    (1
    )
  (1)
    Includes $60 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 included on the Consolidated Balance Sheet as of September 30, 2004 were as follows: Non-Hedge
    
    Hedge
    
    Total(In millions)Current-Other Assets
    
    $
    6
    
    
    $
    6
    
    
    $
    12Other Liabilities
    
    
    (4
    )
    
    
    
    
    
    
    (4
    )Non-Current-Other Deferred Charges
    
    
    61
    
    
    
    31
    
    
    
    92Other Liabilities
    
    
    
    
    
    
    (3
    )
    
    
    (3
    )Net assets
    
    $
    63
    
    
    $
    34
    
    
    $
    97
 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: Source of Information Fair Value by Contract Year
    
    2004(1)
    
    2005
    
    2006
    
    2007
    
    Thereafter
    
    Total(In millions)Prices actively quoted(2)
    
    $
    1
    
    
    $
    4
    
    
    $
    1
    
    
    $
    
    
    
    $
    
    
    
    $
    6Other external sources(3)
    
    
    9
    
    
    
    12
    
    
    
    10
    
    
    
    
    
    
    
    
    
    
    
    31Prices based on models
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    10
    
    
    
    23
    
    
    
    33Total(4)
    
    $
    10
    
    
    $
    16
    
    
    $
    11
    
    
    $
    10
    
    
    $
    23
    
    
    $
    70
  (1)
    For the last quarter of 2004.  (2)
    Exchange traded.  (3)
    Broker quote sheets.  (4)
    Includes $60 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 September 30, 50




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##### Table of Contents



2004. Based on derivative contracts held as of September 30, 2004, an adverse
10% change in commodity prices would decrease net income by approximately $2
million during the next twelve months. Interest Rate Swap Agreements FirstEnergy enters 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 $10 million lower in the
third quarter of 2004, compared to being $5 million lower in the third quarter
of 2003. As of September 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
3.02%. September 30, 2004
    
    December 31, 2003Notional
    
    Maturity
    
    Fair
    
    Notional
    
    Maturity
    
    FairInterest Rate Swaps
    
    Amount
    
    Date
    
    Value
    
    Amount
    
    Date
    
    Value(Dollars in millions)Fixed to Floating Rate
(Fair value hedges)
    
    $
    200
    
    
    
    2006
    
    
    $
    1
    
    
    $
    200
    
    
    
    2006
    
    
    $
    1100
    
    
    
    2008
    
    
    
    
    
    
    
    50
    
    
    
    2008
    
    
    
    100
    
    
    
    2010
    
    
    
    1
    
    
    
    100
    
    
    
    2010
    
    
    
    1100
    
    
    
    2011
    
    
    
    3
    
    
    
    100
    
    
    
    2011
    
    
    
    1450
    
    
    
    2013
    
    
    
    9
    
    
    
    350
    
    
    
    2013
    
    
    
    (1
    )100
    
    
    
    2014
    
    
    
    3150
    
    
    
    2015
    
    
    
    (6
    )
    
    
    150
    
    
    
    2015
    
    
    
    (10
    )200
    
    
    
    2016
    
    
    
    10150
    
    
    
    2018
    
    
    
    6
    
    
    
    150
    
    
    
    2018
    
    
    
    150
    
    
    
    2019
    
    
    
    3
    
    
    
    50
    
    
    
    2019
    
    
    
    1100
    
    
    
    2031
    
    
    
    (3
    )$
    1,700
    
    
    
    
    
    
    $
    27
    
    
    $
    1,150
    
    
    
    
    
    
    $
    (6
    )Floating to Fixed Rate (1)
(Cash flow hedges)
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    7
    
    
    
    2005
    
    
    $
    
  (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 $857 million
and $779 million as of September 30, 2004 and December 31, 2003, respectively.
A hypothetical 10% decrease in prices quoted by stock exchanges would result in
an $86 million reduction in fair value as of September 30, 2004. 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 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 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 September 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 that are reflected in the EUOCs
respective state regulatory plans. Those provisions include: 51




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##### Table of Contents




    
    allowing the EUOCs electric customers to select their generation suppliers;
    
    establishing PLR obligations to non-shopping customers in the EUOCs service areas;  
    
    allowing recovery of potentially stranded investment (or
transition costs) not otherwise recoverable in a competitive
generation market;  
    
    itemizing (unbundling) the price of electricity into its
component elements  including generation, transmission,
distribution and stranded costs recovery charges;  
    
    deregulating the EUOCs electric generation businesses;  
    
    continuing regulation of the EUOCs transmission and distribution systems; and  
    
    requiring corporate separation of regulated and unregulated business activities. However, despite these similarities, the specific approach taken by each
state and for each of the Companies varies. 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. 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: September 30,
    
    December 31,
    
    IncreaseRegulatory Assets
    
    2004
    
    2003
    
    (Decrease)(In millions)OE
    
    $
    1,184
    
    
    $
    1,451
    
    
    $
    (267
    )CEI
    
    
    983
    
    
    
    1,056
    
    
    
    (73
    )TE
    
    
    388
    
    
    
    459
    
    
    
    (71
    )Penn
    
    
    
    *
    
    
    28
    
    
    
    (28
    )JCP&L
    
    
    2,147
    
    
    
    2,558
    
    
    
    (411
    )Met-Ed
    
    
    785
    
    
    
    1,028
    
    
    
    (243
    )Penelec
    
    
    294
    
    
    
    497
    
    
    
    (203
    )ATSI
    
    
    12
    
    
    
    
    
    
    
    12Total
    
    $
    5,793
    
    
    $
    7,077
    
    
    $
    (1,284
    )
  *
    
    Changes in Penns net regulatory asset components through September
2004 resulted in net
regulatory liabilities of approximately $4 million included in
Other Noncurrent
Liabilities on the Consolidated Balance Sheet as of September 30,
2004. Regulatory assets by source are as follows: September 30,
    
    December 31,
    
    IncreaseRegulatory Assets By Source
    
    2004
    
    2003
    
    (Decrease)(In millions)Regulatory transition charge
    
    $
    5,159
    
    
    $
    6,427
    
    
    $
    (1,268
    )Customer shopping incentives
    
    
    556
    
    
    
    371
    
    
    
    185Customer receivables for future income taxes
    
    
    268
    
    
    
    340
    
    
    
    (72
    )Societal benefits charge
    
    
    39
    
    
    
    81
    
    
    
    (42
    )Loss on reacquired debt
    
    
    89
    
    
    
    75
    
    
    
    14Postretirement benefits
    
    
    67
    
    
    
    77
    
    
    
    (10
    )Nuclear decommissioning, decontamination
and spent fuel disposal costs
    
    
    (153
    )
    
    
    (96
    )
    
    
    (57
    )Component removal costs
    
    
    (333
    )
    
    
    (321
    )
    
    
    (12
    )Property losses and unrecovered plant costs
    
    
    55
    
    
    
    70
    
    
    
    (15
    )Other
    
    
    46
    
    
    
    53
    
    
    
    (7
    )Total
    
    $
    5,793
    
    
    $
    7,077
    
    
    $
    (1,284
    )
 The Ohio Companies are deferring customer shopping incentives and interest
costs as new regulatory assets in accordance with the transition and rate
stabilization plans. These regulatory assets totaling $556 million as of
September 30, 2004 (OE  $205 million, CEI  $271 million, TE  $80 million)
will be recovered through a surcharge rate equal to the RTC rate in effect when
the transition costs have been fully recovered. Recovery of the new regulatory
assets will begin at that time and amortization of the regulatory assets for
each accounting period will be equal to the surcharge revenue recognized in
each period. 52




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Reliability Initiatives On October 15, 2003, NERC issued a letter to all NERC control areas and
reliability coordinators requesting a review of various reliability practices.
FirstEnergys response confirmed that its review was completed and that various
enhancements were underway to current practices. On February 10, 2004, NERC
issued its Recommended Actions to Prevent and Mitigate the Impacts of Future
Cascading Blackouts, a portion of which were directed at the FirstEnergy
companies and broadly focused on initiatives that were recommended for
completion by June 30, 2004. FirstEnergys detailed implementation plan was
endorsed by the NERC Board of Trustees on May 7, 2004. The various initiatives
recommended by NERC were certified as complete by June 30, 2004, with one minor
exception related to reactive testing of certain generators expected to be
completed later this year. On February 26 and 27, 2004, certain FirstEnergy companies, as part of a
NERC review of control area operations throughout the United States,
participated in a NERC Control Area Readiness Audit. The final audit report,
completed on May 6, 2004, identified positive observations and included various
recommendations for reliability improvement. FirstEnergy reported completion of
those recommendations on June 30, 2004, with one exception related to MISOs
implementation of a voltage stability tool expected to be completed later this
year. On April 5, 2004, the U.S.  Canada Power System Outage Task Force issued
a Final Report on the August 14, 2003 power outages. The Final Report contains
46 recommendations to prevent or minimize the scope of future blackouts.
Forty-five of those recommendations relate to broad industry or policy matters
while one relates to activities the Task Force recommended be undertaken by
FirstEnergy, MISO, PJM and ECAR. FirstEnergy completed the Task Force
recommendations that were directed toward FirstEnergy and reported completion
of those activities on June 30, 2004. With respect to each of the foregoing initiatives, FirstEnergy requested
and NERC provided, a technical assistance team of experts to provide ongoing
guidance and assistance in implementing and confirming timely and successful
completion. NERC further assembled an independent verification team to confirm
implementation of the foregoing initiatives required to be completed as of June
30, 2004. The NERC Verification Team reported, on July 14, 2004, that
FirstEnergy has completed the recommended policies, procedures and actions
required to be completed by June 30, 2004 or summer 2004, with exceptions noted
by FirstEnergy. Implementation of the recommendations has not required
incremental material investment or upgrades to existing equipment. On March 1, 2004, certain FirstEnergy companies filed, in accordance with
a November 25, 2003 order from the PUCO, their plan for addressing certain
issues identified by the PUCO from the U.S.  Canada Power System Outage Task
Force interim report. In particular, the filing addressed upgrades to
FirstEnergys control room computer hardware and software and enhancements to
the training of control room operators. The PUCO will review the plan before
determining the next steps, if any, in the proceeding. On April 22, 2004, FirstEnergy filed with the FERC the results of the
FERC-ordered independent study of part of Ohios power grid. The study
examined, among other things, the reliability of the transmission grid in
critical points in the Northern Ohio area and the need, if any, for reactive
power reinforcements during summers 2004 and 2009. Certain requested
additional clarifications were provided to the FERC in October 2004.
FirstEnergy completed the implementation of recommendations relating to 2004 by
June 30, 2004, and is continuing to review results related to 2009. The
estimated capital expenditures required by 2009 are not expected to have a
material adverse effect on FirstEnergys financial results. FirstEnergy notes,
however, that FERC or other applicable government agencies and reliability
coordinators may take a different view as to recommended enhancements or may
recommend additional enhancements in the future that could require additional,
material expenditures. In late 2003, the PPUC issued a Tentative Order implementing new
reliability benchmarks and standards. In connection therewith, the PPUC
commenced a rulemaking procedure to amend the Electric Service Reliability
Regulations to implement these new benchmarks, and required additional
reporting on reliability. The PPUC ordered all Pennsylvania utilities to begin
filing quarterly reports on November 1, 2003. On May 11, 2004, the PPUC issued
an order approving the revised reliability benchmark and standards, including
revised benchmarks and standards for Met-Ed, Penelec and Penn. The Order
permitted Pennsylvania utilities to file in a separate proceeding to revise the
recomputed benchmarks and standards if they have evidence, such as the impact
of automated outage management systems, on the accuracy of the PPUC computed
reliability indices. Met-Ed, Penelec and Penn filed a Petition for Amendment of
Benchmarks with the PPUC on May 26, 2004, seeking amendment of the benchmarks
and standards due to their implementation of automated outage management
systems following restructuring. No procedural schedule or hearing date has
been set for this proceeding. FirstEnergy is unable to predict the outcome of
this proceeding. On January 16, 2004, the PPUC initiated a formal investigation of whether
Met-Eds, Penelecs and Penns service reliability performance deteriorated to
a point below the level of service reliability that existed prior to
restructuring in Pennsylvania. Hearings were held in early August 2004. On
September 30, 2004, Met-Ed, Penelec and Penn filed a settlement agreement with
the PPUC that addresses the issues related to this investigation. As part of
the 53




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settlement, Met-Ed, Penelec and Penn agreed to enhance service reliability,
performance reporting and communications with customers and to collectively
maintain their current spending levels of at least $255 million annually on
combined capital and operation and maintenance expenditures for transmission
and distribution for the years 2005 through 2007. In November 2004, the PPUC accepted the recommendation of the ALJ approving the settlement. Ohio FirstEnergys transition plan for the Ohio Companies 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 Companies 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 Companies 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. On October 21, 2003, the Ohio Companies filed an application with the PUCO
to establish generation service rates beginning January 1, 2006, in response to
expressed concerns by the PUCO about price and supply uncertainty following the
end of the market development period. The filing included two options:  
    
    A competitive auction, which would establish a price for
generation that customers would be charged during the period
covered by the auction, or  
    
    A Rate Stabilization Plan, which would extend current
generation prices through 2008, ensuring adequate generation
supply at stable prices, and continuing the Ohio Companies
support of energy efficiency and economic development efforts. Under that proposal, the Ohio Companies requested:  
    
    Extension of the transition cost amortization period for
OE from 2006 to 2007; for CEI from 2008 to 2009 and for TE from
mid-2007 to 2008;  
    
    Deferral of interest costs on the accumulated shopping
incentives and other cost deferrals as new regulatory assets;
and  
    
    Ability to initiate a request to increase generation
rates under certain limited conditions. On February 23, 2004, after consideration of the PUCO Staff comments and
testimony as well as those provided by some of the intervening parties, the
Ohio Companies made certain modifications to the Rate Stabilization Plan. On
June 9, 2004, the PUCO issued an order approving the revised Rate Stabilization
Plan, subject to conducting a competitive bid process on or before December 1,
2004. In addition to requiring the competitive bid process, the PUCO made
other modifications to the Ohio Companies revised Rate Stabilization Plan
application. Among the major modifications were the following:  
    
    Limiting the ability of the Ohio Companies to request
adjustments in generation charges during 2006 through 2008 for
increases in taxes;  
    
    Expanding the availability of market support generation;  
    
    Revising the kilowatt-hour target level and the time period for recovering regulatory transition charges;  
    
    Establishing a 3-year competitive bid process for generation;  
    
    Establishing the 2005 generation credit for shopping
customers, which would be extended as a cap through 2008; and 54




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
    
    Denying the ability to defer costs for future recovery
of distribution reliability improvement expenditures. On June 18, 2004, the Ohio Companies filed with the PUCO an application
for rehearing of the modified version of the Rate Stabilization Plan. Several
other parties also filed applications for rehearing. On August 4, 2004, the
PUCO issued an Entry on Rehearing modifying its June 9, 2004 Order. The
modifications included the following:  
    
    Expanding the Ohio Companies ability to request
adjustments in generation charges during 2006 through 2008 to
include increases in the cost of fuel (including the cost of
emission allowances consumed, lime, stabilizers and other
additives and fuel disposal) using 2002 as the base year. Any
increases in fuel costs would be subject to downward adjustments
in subsequent years should fuel costs decline, but not below the
generation rate initially established in the Rate Stabilization
Plan;  
    
    Approving the revised kilowatt-hour target level and
time period for recovery of regulatory transition costs as
presented by the Ohio Companies in their rehearing application;  
    
    Retaining the requirement for expanded availability of
market support generation, but adopting the Ohio Companies
alternative approach that conditions expanded availability on
higher pricing and eliminating the requirement to reduce the
interest deferral for certain affected rate schedules;  
    
    Revising the calculation of the shopping credit cap for
certain commercial and small industrial rate schedules; and  
    
    Relaxing the notice requirement for availability of
enhanced shopping credits in a number of instances. On August 5, 2004, the Ohio Companies accepted the Rate Stabilization Plan
as modified and approved by the PUCO on August 4, 2004. The Ohio Companies
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 Companies implemented the accounting modifications
contained in the PUCOs June 9, 2004 Order, which are consistent with the
PUCOs August 4, 2004 Entry on Rehearing. Those modifications included
amortization of transition costs based on extended amortization periods (that
are no later than 2007 for OE, mid-2009 for CEI and mid-2008 for TE) and the
deferral of interest costs on the accumulated deferred shopping incentives. On
October 1, 2004, the OCC filed an appeal with the Ohio Supreme Court to
overturn the June 9, 2004 PUCO order. The Ohio Companies filed a proposed competitive bid process which the PUCO
modified on October 6, 2004. The PUCO approved the rules for the competitive
bid process setting a three-year supply period (2006-2008) requirement for
generation service suppliers and a load cap for individual suppliers. In
mid-October, the initial auction schedule was revised so that Part 1 and Part 2
auction bidder applications are due November 4, 2004 and November 15,
respectively, the trial auction is scheduled to occur on December 3, the
auction would commence December 8 and the PUCO will accept or reject auction
results within two business days after the completion of the auction.
FirstEnergy has elected to not participate in the auction. 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, the decision also required
that, within approximately one year of its issuance, JCP&L would initiate
another proceeding to request recovery of additional costs incurred to enhance
system reliability. In that Phase II proceeding, the NJBPU could increase
JCP&Ls return on equity to 9.75% or decrease it to 9.25%, depending on its
assessment of the reliability of JCP&Ls service. Any reduction would be
retroactive to August 1, 2003. The net revenue decrease from the NJBPUs
decision consists of a $223 million decrease in the electricity delivery
charge, a $111 million increase due to the August 1, 2003 expiration of annual
customer credits previously mandated by the New Jersey transition legislation,
a $49 million increase in the MTC tariff component, and a net $1 million
increase in the SBC. The decision in the deferred balances proceeding
disallowed $153 million of deferred energy costs, so that the MTC allows for
the recovery of $465 million in deferred energy costs over the next ten years
on an interim basis. As a result, JCP&L 55




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recorded charges to net income for the year ended December 31, 2003,
aggregating $185 million ($109 million net of tax) consisting of the $153
million of disallowed deferred energy costs and $32 million of other disallowed
regulatory assets. JCP&L filed an interim motion for rehearing and
reconsideration with the NJBPU on August 15, 2003 with respect to the following
issues: (1) the disallowance of the $153 million deferred energy costs; (2) the
reduced rate of return on equity; and (3) $42.7 million of disallowed costs to
achieve merger savings. In its final decision and order issued on May 17, 2004,
the NJPBU clarified the method for calculating interest attributable to the
cost disallowances, resulting in a $5.4 million reduction from the amount
estimated in 2003. On June 1, 2004, JCP&L filed with the NJBPU a supplemental
and amended motion for rehearing and reconsideration. On July 7, 2004, the
NJBPU granted limited reconsideration and rehearing on the following issues:
(1) deferred cost disallowances, (2) the capital structure including the rate
of return, (3) merger savings, including amortization of costs to achieve
merger savings; and (4) decommissioning. All other issues included in JCP&Ls
amended motion were denied. Oral arguments were held on August 4, 2004.
Management is unable to predict when a decision may be reached by the NJBPU. On July 5, 2003, JCP&L experienced a series of 34.5 kilovolt
sub-transmission line faults that resulted in outages on the New Jersey shore.
The NJBPU instituted an investigation into these outages, and directed that a
Special Reliability Master (SRM) be hired to oversee the investigation. On
December 8, 2003, the SRM issued his Interim Report recommending that JCP&L
implement a series of actions to improve reliability in the area affected by
the outages. The NJBPU adopted the findings and recommendations of the Interim
Report on December 17, 2003, and ordered JCP&L to implement the recommended
actions on a staggered basis, with initial actions to be completed by March 31,
2004. In late 2003, in accordance with a Settlement Stipulation concerning an
August 2002 storm outage, the NJBPU engaged Booth & Associates to conduct an
audit of the planning, operations and maintenance practices, policies and
procedures of JCP&L. The audit was expanded to include the July 2003 outage and
was completed in January 2004. On June 9, 2004, the NJBPU approved a
stipulation that incorporated the final SRM report and portions of the final
Booth report. The final order was issued by the NJBPU on July 23, 2004. On July 16, 2004, JCP&L filed the Phase II rate filing with the NJBPU
which requested an increase in base rates of $36 million, reflecting the
recovery of system reliability costs and a 9.75% return on equity. The filing
also requests an increase to the MTC deferred balance recovery of approximately
$20 million annually. Discovery/settlement conferences are ongoing. The filing
fulfills the NJBPU requirement that a Phase II proceeding be conducted and that
any expenditures and projects undertaken by JCP&L to increase its system
reliability be reviewed. JCP&L sells all self-supplied energy (NUGs and owned generation) to the
wholesale market with offsetting credits to its deferred energy balances with
the exception of 300 MW from JCP&Ls must run NUG committed supply currently
being used to serve BGS customers pursuant to NJBPU order. The BGS auction for
periods beginning June 1, 2004 was completed in February 2004 and new BGS
tariffs reflecting the auction results became effective June 1, 2004. On May
25, 2004, the NJBPU issued an order adopting a schedule for the BGS post
transition year three process. JCP&L filed its proposal suggesting how BGS
should be procured for year three and beyond. The NJBPU decision on the filing
was announced on October 22, 2004, approving with minor modifications the BGS
procurement process filed by JCP&L and the other New Jersey electric
distribution companies and authorizing the continued use of NUG committed
supply to serve 300 MW of BGS load. The auction is scheduled to take place in
February 2005 for the supply period beginning June 1, 2005. In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on
June 7, 2004 supporting a continuation of the current level and duration of the
funding of TMI-2 decommissioning costs by New Jersey ratepayers without a
reduction, termination or capping of the funding. On September 30, 2004, JCP&L
filed an updated TMI-2 decommissioning study prepared by TLG Services, Inc.
(see Note 2  Asset Retirement Obligations). This study resulted in an updated
total decommissioning cost estimate of $729 million (in 2003 dollars) compared
to the estimated $528 million (in 2003 dollars) from the prior 1995
decommissioning study. Pennsylvania 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
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. 56




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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 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 57




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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 NOV or Compliance Orders to nine
utilities covering 44 power plants, including the W. H. Sammis Plant which is
owned by OE and Penn. In addition, the U.S. Department of Justice filed eight
civil complaints against various investor-owned utilities, which included a
complaint against OE and Penn in the U.S. District Court for the Southern
District of Ohio. These cases are referred to as New Source Review cases. The
NOV and complaint allege violations of the Clean Air Act based on operation and
maintenance of the W. H. Sammis Plant dating back to 1984. The complaint
requests permanent injunctive relief to require the installation of best
available control technology and civil penalties of up to $27,500 per day of
violation. On August 7, 2003, the United States District Court for the Southern
District of Ohio ruled that 11 projects undertaken at the W. H. Sammis Plant
between 1984 and 1998 required pre-construction permits under the Clean Air
Act. The ruling concludes the liability phase of the case, which deals with
applicability of Prevention of Significant Deterioration provisions of the
Clean Air Act. The remedy phase trial to address civil penalties and what, if
any, actions should be taken to further reduce emissions at the plant has been
rescheduled to January 2005 by the Court because the parties are engaged in
meaningful settlement negotiations. The Court indicated in its August 2003
ruling that the remedies it may consider and impose involved a much broader,
equitable analysis, requiring the Court to consider air quality, public health,
economic impact, and employment consequences. The Court may also consider the
less than consistent efforts of the EPA to apply and further enforce the Clean
Air Act. The potential penalties that may be imposed, as well as the capital
expenditures necessary to comply with substantive remedial measures that may be
required, could have a material adverse impact on FirstEnergys, OEs and
Penns respective financial condition and results of operations. While the
parties are engaged in meaningful settlement discussions, management is unable
to predict the ultimate outcome of this matter and no liability has been
accrued as of September 30, 2004. 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. On September 7, 2004, the EPA established new performance standards under
Clean Water Act Section 316(b) for reducing impacts on fish and shellfish from
cooling water intake structures at certain existing large electric generating
plants. The regulations call for reductions in impingement mortality, when
aquatic organisms are pinned against screens or other parts of a cooling water
intake system and entrainment, which occurs when aquatic species are drawn into
a facilitys cooling water system. The Companies are conducting comprehensive
demonstration studies, due in 2008, to determine the operational measures,
equipment or restoration activities, if any, necessary for compliance by their
facilities with the performance standards. FirstEnergy is unable to predict
the outcome of such studies. Depending on the outcome of such studies, the
future cost of compliance with these standards may be substantial. Power Outages and Related Litigation In July 1999, the Mid-Atlantic states experienced a severe heat wave which
resulted in power outages throughout the service territories of many electric
utilities, including JCP&Ls territory. In an investigation into the causes of
the outages and the reliability of the transmission and distribution systems of
all four New Jersey electric utilities, the NJBPU concluded that there was not
a prima facie case demonstrating that, overall, JCP&L provided unsafe,
inadequate or improper service to its customers. Two class action lawsuits
(subsequently consolidated into a single proceeding) were filed in New Jersey
Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking
compensatory and punitive damages arising from the July 1999 service
interruptions in the JCP&L territory. In August 2002, the trial court granted partial summary judgment to JCP&L
and dismissed the plaintiffs claims for consumer fraud, common law fraud,
negligent misrepresentation, and strict products liability. In November 2003,
the trial court granted JCP&Ls motion to decertify the class and denied
plaintiffs motion to permit into evidence their class-wide damage model
indicating damages in excess of $50 million. These class decertification and
damage 58




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rulings were appealed to the Appellate Division. The Appellate Court issued a
decision on July 8, 2004, affirming the decertification of the originally
certified class but remanding for certification of a class limited to those
customers directly impacted by the outages of transformers in Red Bank, New
Jersey. On September 8, 2004, the New Jersey Supreme Court denied the motions
filed by plaintiffs and JCP&L for leave to appeal the decision of the Appellate
Court. FirstEnergy is unable to predict the outcome of these matters and no
liability has been accrued as of September 30, 2004. On August 14, 2003, various states and parts of southern Canada
experienced widespread power outages. The outages effected approximately 1.4
million customers in FirstEnergys service area. On April 5, 2004, the U.S.
Canada Power System Outage Task Force released its final report on the
outages. In the final report, the Task Force concluded, among other things,
that the problems leading to the outages began in FirstEnergys Ohio service
area. Specifically, the final report concludes, among other things, that the
initiation of the August 14, 2003 power outages resulted from an alleged
failure of both FirstEnergy and ECAR to assess and understand perceived
inadequacies within the FirstEnergy system; inadequate situational awareness of
the developing conditions; and a perceived failure to adequately manage tree
growth in certain transmission rights of way. The Task Force also concluded
that there was a failure of the interconnected grids reliability organizations
(MISO and PJM) to provide effective diagnostic support. The final report is
publicly available through the Department of Energys website (www.doe.gov).
FirstEnergy believes that the final report does not provide a complete and
comprehensive picture of the conditions that contributed to the August 14, 2003
power outages and that it does not adequately address the underlying causes of
the outages. FirstEnergy remains convinced that the outages cannot be explained
by events on any one utilitys system. The final report contains 46
recommendations to prevent or minimize the scope of future blackouts.
Forty-five of those recommendations relate to broad industry or policy matters
while one, including subparts, relates to activities the Task Force recommends
be undertaken by FirstEnergy, MISO, PJM, and ECAR. FirstEnergy implemented
several initiatives, both prior to and since the August 14, 2003 power outages,
which are consistent with these and other recommendations and collectively
enhance the reliability of its electric system. FirstEnergy certified to NERC
on June 30, 2004, completion of various reliability recommendations and further
received independent verification of completion status from a NERC verification
team on July 14, 2004 (see 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 September 30, 2004 for any expenditures in excess of
those actually incurred through that date. Three substantially similar actions were filed in various Ohio state
courts by plaintiffs seeking to represent customers who allegedly suffered
damages as a result of the August 14, 2003 power outages. All three cases were
dismissed for lack of jurisdiction. One case was refiled at the PUCO and the
other two have been appealed. In addition to the one case that was refiled at
the PUCO, the Ohio Companies were named as respondents in a regulatory
proceeding that was initiated at the PUCO in response to complaints alleging
failure to provide reasonable and adequate service stemming primarily from the
August 14, 2003 power outages. One complaint has been filed against FirstEnergy in the New York State
Supreme Court. In this case, several plaintiffs in the New York City
metropolitan area allege that they suffered damages as a result of the August
14, 2003 power outages. None of the plaintiffs are customers of any
FirstEnergy affiliate. FirstEnergy filed a motion to dismiss with the Court on
October 22, 2004. No damage estimate has been provided and thus potential
liability has not been determined. FirstEnergy is vigorously defending these actions, but cannot predict the
outcome of any of these proceedings or whether any further regulatory
proceedings or legal actions may be instituted against the Companies. In
particular, if FirstEnergy or its subsidiaries were ultimately determined to
have legal liability in connection with these proceedings, it could have a
material adverse effect on FirstEnergys or its subsidiaries financial
condition and results of operations. Nuclear Plant Matters FENOC received a subpoena in late 2003 from a grand jury sitting in the
United States District Court for the Northern District of Ohio, Eastern
Division requesting the production of certain documents and records relating to
the inspection and maintenance of the reactor vessel head at the Davis-Besse
plant. FirstEnergy is unable to predict the outcome of this investigation. In
addition, FENOC remains subject to possible civil enforcement action by the NRC
in connection with the events leading to the Davis-Besse outage in 2002.
Further, a petition was filed with the NRC on March 29, 2004 by a group
objecting to the NRCs restart order of the Davis-Besse Nuclear Power Station.
The Petition seeks, among other things, suspension of the Davis-Besse operating
license. A June 2, 2004 ASLB denial of the petition was appealed to the NRC.
FENOC and the NRC staff filed opposition briefs on June 24, 2004. If it were
ultimately 59




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determined that FirstEnergy or its subsidiaries has legal liability or is
otherwise made subject to enforcement action based on the Davis-Besse outage,
it could have a material adverse effect on FirstEnergys or its subsidiaries
financial condition and results of operations. On August 12, 2004, the NRC publicly disclosed that it was notifying
FirstEnergy that it will increase its regulatory oversight of the Perry Nuclear
Power Plant as a result of problems with safety system equipment over the past
two years. OE, CEI, TE and Penn own and/or lease the Perry Nuclear Power Plant.
The NRC noted that the plant continues to operate safely. The increased
oversight will include an extensive NRC team inspection to access the equipment
problems and FirstEnergys corrective actions. The outcome of this increased
oversight is not known at this time. Other Legal Matters Various lawsuits, claims (including claims for asbestos exposure) and
proceedings related to FirstEnergys normal business operations are pending
against FirstEnergy and its subsidiaries. The most significant not otherwise
discussed above are described below. On October 20, 2004, FirstEnergy was notified by the SEC that the
previously disclosed informal inquiry initiated by the SECs Division of
Enforcement in September 2003 relating to the restatements in August 2003 of
previously reported results by FirstEnergy and the Ohio Companies and the
Davis-Besse extended outage has become the subject of a formal order of
investigation. The SECs formal order of investigation also encompasses issues
raised during the SECs examination of FirstEnergy and the Companies under the
PUHCA. Concurrent with this notification, FirstEnergy received a subpoena
asking for background documents and documents related to the restatements and
Davis-Besse issues. FirstEnergy has cooperated fully with the informal inquiry
and will continue to do so with the formal investigation. Various legal proceedings alleging violations of federal securities laws
and related state laws were filed against FirstEnergy in connection with, among
other things, the restatements in August 2003 by FirstEnergy and the Ohio
Companies of previously reported results, the August 14, 2003 power outages
described above, and the extended outage at the Davis-Besse Nuclear Power
Station. The lawsuits were filed against FirstEnergy and certain of its
officers and directors. On July 27, 2004, FirstEnergy announced that it had
reached an agreement to resolve these pending lawsuits. The settlement
agreement, which does not constitute any admission of wrongdoing, provides for
a total settlement payment of $89.9 million. Of that amount, FirstEnergys
insurance carriers will pay $71.92 million, based on a contractual
pre-allocation, and FirstEnergy will pay $17.98 million, which resulted in an
after-tax charge against FirstEnergys second quarter and year-to-date 2004
earnings of $11 million or $0.03 per share of common stock (basic and diluted).
The settlement has been preliminarily approved by the court with a final
hearing scheduled for mid-December 2004. Although not anticipated to occur, in
the event that a significant number of shareholders do not accept the terms of
the settlement, FirstEnergy and individual defendants have the right, but not
the obligation, to set aside the settlement and recommence the litigation. On September 16, 2004, the FERC issued an order that imposed additional
obligations on CEI under certain pre-Open Access transmission contracts among
CEI and the cities of Cleveland and Painesville. Under the FERCs decision,
CEI may be responsible for a portion of new energy market charges imposed by
the MISO when its energy markets begin in the spring of 2005. CEI filed for
rehearing of the order from the FERC on October 18, 2004. The impact of the
FERC decision on CEI is dependent upon many factors, including the arrangements
made by the cities for transmission service, the startup date for the MISO
energy market, and the resolution of the rehearing request, and cannot be
determined at this time. If it were ultimately determined that FirstEnergy or its subsidiaries has
legal liability or is otherwise made subject to liability based on any of the
above matters, it could have a material adverse effect on FirstEnergys or its
subsidiaries financial condition and results of operations. 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 60




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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, weather-related impacts and electricity
provided by alternative suppliers. 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 in the first
nine months 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. In the third quarter of 2004, FirstEnergy made a $500 million voluntary
contribution to its pension plan. This contribution will mitigate future 61




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funding requirements and significantly reduce the year-end minimum pension
liability that currently reduces accumulated other comprehensive income by $300
million. 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. 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 annual
review of goodwill was completed in the third quarter of 2004, with no
impairment indicated. 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 nine months of 2004,
FirstEnergy reduced goodwill by $27 million for pre-merger interest received on
an income tax refund and other tax benefits. As of September 30, 2004,
FirstEnergy had $6.1 billion of goodwill that primarily relates to its
regulated services segment. 62




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NEW ACCOUNTING STANDARDS AND INTERPRETATIONS Exposure Draft of Proposed Statement of Financial Accounting Standards
Share-Based Payment an amendment of FASB Statements No. 123 and 95 In March 2004, the FASB issued an exposure draft of a new standard, which
would amend SFAS 123 and SFAS 95. Among other items, the new standard would
require expensing stock options in FirstEnergys financial statements. In
October 2004, the FASB agreed to delay the effective date of the proposed
standard from January 1, 2005 to periods beginning after June 15, 2005, for
calendar year companies. FirstEnergy will not be able to determine the impact
of the proposed standard on its results of operations until the standard is
issued in final form. The 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. Exposure Draft of Proposed Statement of Financial Accounting Standards
Earnings per Share an amendment of FASB Statement No. 128 In December 2003, the FASB issued an exposure draft of a new standard,
which would amend SFAS 128. Among other items, the new standard would eliminate
the provisions of SFAS 128 that allow an entity to rebut the presumption that
contracts with the option of settling in either cash or stock will be settled
in stock. The new standard is expected to be issued in the fourth quarter of
2004 and be effective for all periods ending after December 15, 2004.
Retrospective application to all prior-period earnings per share data presented
would be required. FirstEnergy is continuing to assess the proposed standard
but does not anticipate a material impact on its calculation of earnings per
share. EITF Issue No. 03-1, The Meaning of Other-Than-Temporary and Its
Application to Certain Investments In March 2004, the EITF reached a consensus on the application guidance
for Issue 03-1. EITF 03-1 provides a model for determining when investments in
certain debt and equity securities are considered other than temporarily
impaired. When an impairment is other-than-temporary, the investment must be
measured at fair value and the impairment loss recognized in earnings. The
recognition and measurement provisions of EITF 03-1, which were to be effective
for periods beginning after June 15, 2004, were delayed by the issuance of FSP
EITF 03-1-1 in September 2004. During the period of delay, FirstEnergy will
continue to evaluate its investments as required by existing authoritative
guidance. EITF Issue No. 03-16, Accounting for Investments in Limited Liability
Companies In March 2004, the FASB ratified the final consensus on Issue 03-16. EITF
03-16 requires that an investment in a limited liability company that maintains
a specific ownership account for each investor should be viewed as similar to
an investment in a limited partnership for determining whether the cost or
equity method of accounting should be used. The equity method of accounting is
generally required for investments that represent more than a three to five
percent interest in a limited partnership. EITF 03-16 was adopted by
FirstEnergy in the third quarter of 2004 and did not affect the Companies
financial statements. FSP 106-2, Accounting and Disclosure Requirements Related to the Medicare
Prescription Drug, Improvement and Modernization Act of 2003 Issued in May 2004, FSP 106-2 provides guidance on accounting for the
effects of the Medicare Act for employers that sponsor postretirement health
care plans that provide prescription drug benefits. FSP 106-2 also requires
certain disclosures regarding the effect of the federal subsidy provided by the
Medicare Act. The effect of the federal subsidy provided under the Medicare Act
on FirstEnergys consolidated financial statements is described in Note 4. The
impact of the subsidy was not material to the financial statements of each of
the Companies for the three and nine months ended September 30, 2004. FIN 46 (revised December 2003), Consolidation of Variable Interest
Entities In December 2003, the FASB issued a revised interpretation of ARB 51
referred to as FIN 46R, which requires the consolidation of a VIE by an
enterprise if that enterprise is determined to be the primary beneficiary of
the VIE. As required, FirstEnergy adopted FIN 46R for interests in VIEs
commonly referred to as special-purpose entities effective December 31, 2003
and for all other types of entities effective March 31, 2004. Adoption of FIN
46R did not have a material impact on the consolidated financial statements of
FirstEnergy or the Companies. 63




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OHIO EDISON COMPANY 
 CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited) Three Months Ended
    
    Nine Months EndedSeptember 30,
    
    September 30,2004
    
    2003
    
    2004
    
    2003(In thousands)STATEMENTS OF INCOMEOPERATING REVENUES
    
    $
    766,336
    
    
    $
    774,714
    
    
    $
    2,227,978
    
    
    $
    2,191,165OPERATING EXPENSES AND TAXES:Fuel
    
    
    15,244
    
    
    
    13,978
    
    
    
    44,158
    
    
    
    37,118Purchased power
    
    
    242,835
    
    
    
    231,619
    
    
    
    730,542
    
    
    
    691,802Nuclear operating costs
    
    
    81,244
    
    
    
    98,742
    
    
    
    235,277
    
    
    
    342,319Other operating costs
    
    
    99,132
    
    
    
    106,802
    
    
    
    276,289
    
    
    
    277,402Provision for depreciation and amortization
    
    
    108,185
    
    
    
    121,734
    
    
    
    338,086
    
    
    
    335,872General taxes
    
    
    47,634
    
    
    
    46,863
    
    
    
    135,688
    
    
    
    139,525Income taxes
    
    
    76,502
    
    
    
    66,453
    
    
    
    203,863
    
    
    
    144,533Total operating expenses and taxes
    
    
    670,776
    
    
    
    686,191
    
    
    
    1,963,903
    
    
    
    1,968,571OPERATING INCOME
    
    
    95,560
    
    
    
    88,523
    
    
    
    264,075
    
    
    
    222,594OTHER INCOME
    
    
    17,141
    
    
    
    15,877
    
    
    
    50,285
    
    
    
    44,789NET INTEREST CHARGES:Interest on long-term debt
    
    
    10,657
    
    
    
    21,241
    
    
    
    43,641
    
    
    
    70,686Allowance for borrowed funds used during construction and
capitalized interest
    
    
    (1,950
    )
    
    
    (1,668
    )
    
    
    (4,924
    )
    
    
    (4,172
    )Other interest expense
    
    
    640
    
    
    
    3,416
    
    
    
    7,576
    
    
    
    15,219Subsidiarys preferred stock dividend requirements
    
    
    639
    
    
    
    639
    
    
    
    1,919
    
    
    
    2,463Net interest charges
    
    
    9,986
    
    
    
    23,628
    
    
    
    48,212
    
    
    
    84,196INCOME BEFORE CUMULATIVE EFFECT OF
ACCOUNTING CHANGE
    
    
    102,715
    
    
    
    80,772
    
    
    
    266,148
    
    
    
    183,187Cumulative effect of accounting change (net of income
taxes of $22,389,000) (Note 2)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    31,720NET INCOME
    
    
    102,715
    
    
    
    80,772
    
    
    
    266,148
    
    
    
    214,907PREFERRED STOCK DIVIDEND REQUIREMENTS
    
    
    623
    
    
    
    659
    
    
    
    1,843
    
    
    
    1,977EARNINGS ON COMMON STOCK
    
    $
    102,092
    
    
    $
    80,113
    
    
    $
    264,305
    
    
    $
    212,930STATEMENTS OF COMPREHENSIVE INCOMENET INCOME
    
    $
    102,715
    
    
    $
    80,772
    
    
    $

    266,148
    
    
    $
    214,907OTHER COMPREHENSIVE INCOME (LOSS):Minimum liability for unfunded retirement benefits
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (86,076
    )Unrealized gain (loss) on available for sale securities
    
    
    (6,913
    )
    
    
    4,156
    
    
    
    (2,767
    )
    
    
    19,462Other comprehensive income (loss)
    
    
    (6,913
    )
    
    
    4,156
    
    
    
    (2,767
    )
    
    
    (66,614
    )Income tax related to other comprehensive income
    
    
    2,850
    
    
    
    (1,717
    )
    
    
    1,141
    
    
    
    27,471Other comprehensive income (loss), net of tax
    
    
    (4,063
    )
    
    
    2,439
    
    
    
    (1,626
    )
    
    
    (39,143
    )TOTAL COMPREHENSIVE INCOME
    
    $
    98,652
    
    
    $
    83,211
    
    
    $
    264,522
    
    
    $
    175,764
 The preceding Notes to Consolidated Financial Statements as they relate to Ohio
Edison Company are an integral part of these statements. 64




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OHIO EDISON COMPANY 
 CONSOLIDATED BALANCE SHEETS
(Unaudited) September 30,
    
    December 31,2004
    
    2003(In thousands)ASSETSUTILITY PLANT:In service
    
    $
    5,376,250
    
    
    $
    5,269,042Less-Accumulated provision for depreciation
    
    
    2,683,177
    
    
    
    2,578,8992,693,073
    
    
    
    2,690,143Construction work in progress-Electric plant
    
    
    181,746
    
    
    
    145,380Nuclear Fuel
    
    
    19,412
    
    
    
    554201,158
    
    
    
    145,9342,894,231
    
    
    
    2,836,077OTHER PROPERTY AND INVESTMENTS:Investment in lease obligation bonds
    
    
    370,036
    
    
    
    383,510Certificates of deposit
    
    
    
    
    
    
    277,763Nuclear plant decommissioning trusts
    
    
    410,768
    
    
    
    376,367Long-term notes receivable from associated companies
    
    
    208,645
    
    
    
    508,594Other
    
    
    50,298
    
    
    
    59,1021,039,747
    
    
    
    1,605,336CURRENT ASSETS:Cash and cash equivalents
    
    
    1,279
    
    
    
    1,883Receivables-Customers (less accumulated provisions of $8,785,000 and $8,747,000, respectively,
for uncollectible accounts)
    
    
    267,652
    
    
    
    280,538Associated companies
    
    
    469,911
    
    
    
    436,991Other (less accumulated provisions of $563,000 and $2,282,000, respectively,
for uncollectible accounts)
    
    
    20,138
    
    
    
    28,308Notes receivable from associated companies
    
    
    635,741
    
    
    
    366,501Materials and supplies, at average cost
    
    
    88,609
    
    
    
    79,813Prepayments and other
    
    
    16,026
    
    
    
    14,3901,499,356
    
    
    
    1,208,424DEFERRED CHARGES:Regulatory assets
    
    
    1,183,707
    
    
    
    1,477,969Property taxes
    
    
    59,279
    
    
    
    59,279Unamortized sale and leaseback costs
    
    
    61,589
    
    
    
    65,631Other
    
    
    67,207
    
    
    
    64,2141,371,782
    
    
    
    1,667,093$
    6,805,116
    
    
    $
    7,316,930CAPITALIZATION AND LIABILITIESCAPITALIZATION:Common stockholders equity-Common stock, without par value, authorized 175,000,000 shares - 100 shares
outstanding
    
    $
    2,098,729
    
    
    $
    2,098,729Accumulated other comprehensive loss
    
    
    (40,319
    )
    
    
    (38,693
    )Retained earnings
    
    
    548,239
    
    
    
    522,934Total common stockholders equity
    
    
    2,606,649
    
    
    
    2,582,970Preferred stock not subject to mandatory redemption
    
    
    60,965
    
    
    
    60,965Preferred stock of consolidated subsidiary not subject to mandatory redemption
    
    
    39,105
    
    
    
    39,105Long-term debt and other long-term obligations
    
    
    1,101,179
    
    
    
    1,179,7893,807,898
    
    
    
    3,862,829CURRENT LIABILITIES:Currently payable long-term debt
    
    
    432,406
    
    
    
    466,589Short-term borrowings-Associated companies
    
    
    22,123
    
    
    
    11,334Other
    
    
    174,010
    
    
    
    171,540Accounts payable-Associated companies
    
    
    291,679
    
    
    
    271,262Other
    
    
    9,467
    
    
    
    7,979Accrued taxes
    
    
    213,427
    
    
    
    560,345Accrued interest
    
    
    21,632
    
    
    
    18,714Other
    
    
    101,138
    
    
    
    58,6801,265,882
    
    
    
    1,566,443NONCURRENT LIABILITIES:Accumulated deferred income taxes
    
    
    763,283
    
    
    
    867,691Accumulated deferred investment tax credits
    
    
    65,989
    
    
    
    75,820Asset retirement obligation
    
    
    333,644
    
    
    
    317,702Retirement benefits
    
    
    283,548
    
    
    
    331,829Other
    
    
    284,872
    
    
    
    294,6161,731,336
    
    
    
    1,887,658COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 3)$
    6,805,116
    
    
    $
    7,316,930
 The preceding Notes to Consolidated Financial Statements as they relate to Ohio
Edison Company are an integral part of these balance sheets. 65




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##### Table of Contents



OHIO EDISON COMPANY 
 CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited) Three Months Ended
    
    Nine Months EndedSeptember 30,
    
    September 30,2004
    
    2003
    
    2004
    
    2003(In thousands)CASH FLOWS FROM OPERATING ACTIVITIES:Net income
    
    $
    102,715
    
    
    $
    80,772
    
    
    $
    266,148
    
    
    $
    214,907Adjustments to reconcile net income to net cash from
operating activitiesProvision for depreciation and amortization
    
    
    108,185
    
    
    
    121,734
    
    
    
    338,086
    
    
    
    335,872Nuclear fuel and lease amortization
    
    
    11,914
    
    
    
    10,542
    
    
    
    33,766
    
    
    
    28,411Deferred income taxes, net
    
    
    (7,376
    )
    
    
    (30,010
    )
    
    
    (50,658
    )
    
    
    (50,714
    )Investment tax credits, net
    
    
    (3,998
    )
    
    
    (3,681
    )
    
    
    (11,303
    )
    
    
    (11,077
    )Cumulative effect of accounting change (Note 2)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (54,109
    )Pension trust contribution
    
    
    (72,763
    )
    
    
    
    
    
    
    (72,763
    )
    
    
    Receivables
    
    
    (86,506
    )
    
    
    329,852
    
    
    
    (10,734
    )
    
    
    (50,930
    )Materials and supplies
    
    
    (2,930
    )
    
    
    (956
    )
    
    
    (8,796
    )
    
    
    4,715Deferred lease costs
    
    
    33,037
    
    
    
    33,977
    
    
    
    30,585
    
    
    
    31,300Prepayments and other current assets
    
    
    4,878
    
    
    
    3,514
    
    
    
    (1,636
    )
    
    
    (6,285
    )Accounts payable
    
    
    115,690
    
    
    
    (141,910
    )
    
    
    21,905
    
    
    
    113,508Accrued taxes
    
    
    (4,464
    )
    
    
    131,470
    
    
    
    (346,918
    )
    
    
    180,604Accrued interest
    
    
    3,028
    
    
    
    (417
    )
    
    
    2,918
    
    
    
    (5,523
    )Accrued retirement benefit obligations
    
    
    7,253
    
    
    
    20,471
    
    
    
    24,482
    
    
    
    31,652Accrued compensation, net
    
    
    1,106
    
    
    
    366
    
    
    
    5,138
    
    
    
    (8,111
    )Other
    
    
    (6,016
    )
    
    
    (6,774
    )
    
    
    (4,768
    )
    
    
    (1,220
    )Net cash provided from operating activities
    
    
    203,753
    
    
    
    548,950
    
    
    
    215,452
    
    
    
    753,000CASH FLOWS FROM FINANCING ACTIVITIES:New FinancingLong-term debt
    
    
    
    
    
    
    
    
    
    
    30,000
    
    
    
    575,000Short-term borrowings, net
    
    
    91,072
    
    
    
    
    
    
    
    13,258
    
    
    
    Redemptions and RepaymentsLong-term debt
    
    
    (36,090
    )
    
    
    (209,111
    )
    
    
    (152,900
    )
    
    
    (467,567
    )Short-term borrowings, net
    
    
    
    
    
    
    (4,547
    )
    
    
    
    
    
    
    (223,137
    )Dividend PaymentsCommon stock
    
    
    (68,000
    )
    
    
    (94,000
    )
    
    
    (239,000
    )
    
    
    (379,000
    )Preferred stock
    
    
    (623
    )
    
    
    (659
    )
    
    
    (1,843
    )
    
    
    (1,977
    )Net cash used for financing activities
    
    
    (13,641
    )
    
    
    (308,317
    )
    
    
    (350,485
    )
    
    
    (496,681
    )CASH FLOWS FROM INVESTING ACTIVITIES:Property additions
    
    
    (61,682
    )
    
    
    (39,432
    )
    
    
    (146,645
    )
    
    
    (141,126
    )Contributions to nuclear decommissioning trusts
    
    
    (7,885
    )
    
    
    (15,770
    )
    
    
    (23,655
    )
    
    
    (23,655
    )Loan repayments from (loans to) associated companies, net
    
    
    (378,081
    )
    
    
    (197,289
    )
    
    
    30,709
    
    
    
    (146,010
    )Proceeds from certificates of deposits
    
    
    277,763
    
    
    
    
    
    
    
    277,763
    
    
    
    Other
    
    
    (20,612
    )
    
    
    11,286
    
    
    
    (3,743
    )
    
    
    35,752Net cash provided from (used for) investing activities
    
    
    (190,497
    )
    
    
    (241,205
    )
    
    
    134,429
    
    
    
    (275,039
    )Net decrease in cash and cash equivalents
    
    
    (385
    )
    
    
    (572
    )
    
    
    (604
    )
    
    
    (18,720
    )Cash and cash equivalents at beginning of period
    
    
    1,664
    
    
    
    2,364
    
    
    
    1,883
    
    
    
    20,512Cash and cash equivalents at end of period
    
    $
    1,279
    
    
    $
    1,792
    
    
    $
    1,279
    
    
    $
    1,792
 The preceding Notes to Consolidated Financial Statements as they relate to Ohio
Edison Company are an integral part of these statements. 66




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##### Table of Contents



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 September 30, 2004, and the related
consolidated statements of income, comprehensive income and cash flows for each
of the three-month and nine-month periods ended September 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
November 2, 2004 67




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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. The OE
Companies also provide generation services to those customers electing to
retain the OE Companies 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 third quarter of 2004 increased to $102
million from $80 million in the third quarter of 2003. For the first nine
months of 2004, earnings on common stock increased to $264 million from $213
million in the same period of 2003. Earnings on common stock in the first nine
months of 2003 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 $183 million in the first nine months of 2003.
Increased earnings in both 2004 periods resulted principally from lower nuclear
operating costs and reduced interest charges  partially offset by higher
purchased power costs compared to 2003. Lower nuclear operating costs in the
third quarter and the first nine months of 2004, compared with the same periods
of 2003, were due to the absence of nuclear refueling outages at the Beaver
Valley Units and the Perry Plant in 2003. Lower net interest charges in the
third quarter and the first nine months of 2004, compared with the same periods
of 2003, were primarily due to debt redemptions. Reduced provisions for
depreciation and amortization in the third quarter of 2004 and higher
operating revenues in the first nine months of 2004 also contributed to
increased earnings for those respective periods. Operating revenues decreased by $8 million or 1.1% in the third quarter
of 2004 from the same period of 2003. Lower revenues primarily resulted from a
$13 million decrease in retail electric revenues which was partially offset by
a $6 million (3.5%) increase in wholesale sales (primarily to FES) due to
increased available nuclear generation. The net decrease in retail electric
revenues reflected lower distribution throughput revenues and increased
shopping incentive credits (reflecting an increase in the shopping credit rate
in Ohio) which was partially offset by a $3 million increase in retail
generation revenues. Lower kilowatt-hour sales to residential customers
resulting from cooler weather which reduced air conditioning loads were
partially offset by the effect of a stronger economy in OEs service area. A
$4 million increase in retail generation revenues to the commercial sector
reflected a 1.7 percentage points decrease in electric generation services
provided by alternative suppliers as a percent of total sales deliveries in the
OE Companies franchise areas. Revenues from sales to residential customers
decreased by $2 million as the corresponding percentage for shopping increased
by 0.9 percentage points in the third quarter of 2004. Generation revenues from
industrial customers were relatively flat as the percentage of customers
shopping did not change. Operating revenues increased by $37 million (1.7%) in the first nine
months of 2004 compared with the same period in 2003 primarily due to a $36
million increase in wholesale sales. Revenues from wholesale sales to FES
(resulting from increased nuclear generation available for sale) increased by
$48 million, and was partially offset by $11 million of lower revenues due to
the expiration of a contract in July 2003. Increased retail generation revenues
of $15 million in the first nine months of 2004 reflected the same trend in
shopping for generation providers (an increase of 1.8 percentage points for
residential customers and decreases of 0.6 and 1.8 percentage points for
commercial and industrial customers, respectively). Commercial and industrial
revenues increased due to higher kilowatt-hour sales and unit prices which were
partially offset by lower kilowatt-hour sales to residential customers. Revenues from distribution throughput decreased by $4 million in the third
quarter of 2004, but increased $1 million in the first nine months of 2004
compared with the corresponding periods of 2003. Distribution deliveries to
residential customers decreased 1.6% in the third quarter of 2004 due to
weather conditions as discussed above. Revenues from distribution deliveries to
residential customers decreased by $7 million in the third quarter and $4
million in the first nine months of 2004 compared to the same periods of 2003
principally reflecting lower unit prices. Higher unit prices and increased
distribution deliveries to commercial customers, as a result of the improving
economy, increased revenues. Lower unit prices were the primary factors in the
decrease in revenues from industrial customers. Under the Ohio transition plan, OE provides incentives to customers to
encourage switching to alternative energy providers  $11 million of additional
credits in the third quarter and $12 million of additional credits in the first
nine months of 2004 compared with the corresponding periods of 2003. These
revenue reductions are deferred for future recovery under OEs transition plan
and do not materially affect current period earnings. 68




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Changes in electric generation sales and distribution deliveries in the
third quarter and first nine months of 2004 from the corresponding periods of
2003 are summarized in the following table: Changes in KWH Sales
    
    Three Months
    
    Nine MonthsIncrease (Decrease)Electric Generation:Retail
    
    
    (0.2
    )%
    
    
    0.8
    %Wholesale
    
    
    8.8
    %
    
    
    13.8
    %Total Electric Generation Sales
    
    
    4.1
    %
    
    
    6.7
    %Distribution Deliveries:Residential
    
    
    (1.6
    )%
    
    
    0.7
    %Commercial
    
    
    1.3
    %
    
    
    1.9
    %Industrial
    
    
    (0.5
    )%
    
    
    (0.2
    )%Total Distribution Deliveries
    
    
    (0.5
    )%
    
    
    0.6
    %
 Operating Expenses and Taxes Total operating expenses and taxes decreased $15 million in the third
quarter and $5 million in the first nine 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
    
    Nine MonthsIncrease (Decrease)
    
    (In millions)Fuel
    
    $
    1
    
    
    $
    7Purchased power costs
    
    
    11
    
    
    
    39Nuclear operating costs
    
    
    (17
    )
    
    
    (107
    )Other operating costs
    
    
    (8
    )
    
    
    (1
    )Total operation and maintenance expenses
    
    
    (13
    )
    
    
    (62
    )Provision for depreciation and amortization
    
    
    (13
    )
    
    
    2General taxes
    
    
    1
    
    
    
    (4
    )Income taxes
    
    
    10
    
    
    
    59Total operating expenses and taxes
    
    $
    (15
    )
    
    $
    (5
    )
 Higher fuel costs in the third quarter and first nine months of 2004,
compared with the same periods of 2003, resulted from increased nuclear
generation  up 8.7% and 23.7%, respectively. Purchased power costs were higher
in both periods of 2004 reflecting higher unit costs and increased
kilowatt-hour purchases from nonaffiliated wholesale customers. Lower nuclear
operating costs for both periods were due to the absence of refueling outages
in 2004  refueling outages were performed at Beaver Valley Unit 1 (100%
interest), Perry plant (35.24% interest) and Beaver Valley Unit 2 (55.62%
interest) in the first, second and third quarters of 2003, respectively. The
decrease in other operating costs in the third quarter and first nine months of
2004, compared to the same periods of 2003, is due to reduced labor costs and
lower employee benefits expenses. Depreciation and amortization decreased in the third quarter of 2004
compared to the same period of 2003 primarily due to higher shopping incentive
deferrals ($11 million) and deferred interest on the shopping incentives (see
Regulatory Matters) in the third quarter of 2004 ($3 million). The increase in
depreciation and amortization in the first nine months of 2004, compared with
the first nine months of 2003 was primarily due to the increased amortization
of Ohio transition regulatory assets ($18 million), lower tax-related deferrals
($4 million), offset by higher shopping incentive deferrals ($12 million) and
deferred interest on shopping incentives ($7 million). General taxes decreased in the first nine months of 2004 from the same
period of 2003, primarily due to a $6 million refund received on a real estate
valuation settlement. Net Interest Charges Net interest charges continued to trend lower, decreasing by $14 million
in the third quarter and $36 million in the first nine months of 2004 from the
same periods last year, reflecting redemptions and refinancings since the end
of the third quarter of 2003. OEs long-term debt redemptions (excluding
revolving credit facility activity) totaled $105 million during the first nine
months of 2004, which is expected to result in annualized savings of
approximately $8 million. 69




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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 As of September 30, 2004, OE had $1 million of cash and cash equivalents,
compared with $2 million as of December 31, 2003. The major sources of changes
in these balances are summarized below. Cash Flows From Operating Activities Cash provided from operating activities during the third quarter and first
nine months of 2004, compared with the corresponding periods in 2003, were as
follows: Three Months Ended
    
    Nine Months EndedSeptember 30,
    
    September 30,Operating Cash Flows
    
    2004
    
    2003
    
    2004
    
    2003(In millions)Cash earnings(1)
    
    $
    253
    
    
    $
    234
    
    
    $
    636
    
    
    $
    518Pension trust contribution
    
    
    (73
    )
    
    
    
    
    
    
    (73
    )
    
    
    Working capital and other
    
    
    24
    
    
    
    315
    
    
    
    (348
    )
    
    
    235Total
    
    $
    204
    
    
    $
    549
    
    
    $
    215
    
    
    $
    753
  (1)
    Includes net income, depreciation and
amortization, deferred income taxes, investment tax
credits and major noncash charges. Net cash from operating activities decreased $345 million in the third
quarter of 2004 from the third quarter of 2003 due to a $291 million decrease
from changes in working capital and a voluntary pension trust contribution of
$73 million. These decreases were partially offset in part by a $19 million
increase in cash earnings as described above under Results from Operations.
The change in working capital primarily reflects an increase in accounts
receivable from associated companies and a decrease in accrued tax due to
higher estimated tax payments in the third quarter of 2004 compared with the
third quarter of 2003. These changes were partially offset by an increase in
accounts payable. Net cash from operating activities decreased $538 million in
the first nine months of 2004 due to a $583 million decrease from changes in
working capital and the $73 million pension contribution. These decreases were
partially offset by a $118 million increase in cash earnings. The change in
working capital primarily reflects lower 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. Cash Flows From Financing Activities In the third quarter of 2004, net cash used for financing activities was
$14 million compared to $308 million in the third quarter of 2003. The change
resulted from a $173 million decrease in net debt redemptions, a $96 million
net increase in short-term borrowings and a $26 million decrease in common
stock dividend payments to FirstEnergy. In the first nine months of 2004, net
cash used for financing activities decreased to $350 million from $496 million
in the same period last year. The decrease resulted from reduced payments on
short-term borrowings of $236 million and $140 million of reduced common stock
dividends to FirstEnergy, partially offset by $230 million of reduced
financings in 2004. On June 7, 2004, OE replaced certain collateralized LOCs 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 LOCs and was used to repay short-term debt and for other
corporate purposes. Simultaneously with the issuance of the replacement LOCs,
OE entered into a Credit Agreement pursuant to which a standby LOC was issued
in support of the replacement LOCs, and the issuer of the LOCs obtained 70




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##### Table of Contents



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 $637 million of cash and temporary investments (which
include short-term notes receivable from associated companies) and
approximately $196 million of short-term indebtedness as of September 30, 2004.
Available borrowing capability under bilateral bank facilities totaled $14
million as of September 30, 2004. OE has obtained authorization from the PUCO
to incur short-term debt of up to $500 million (including bank facilities and
the utility money pool described below). Penn has obtained authorization from
the SEC to incur short-term debt up to its charter limit of $46 million
(including the utility money pool). OE and Penn had the capability to issue
$1.6 billion and $497 million, respectively, of additional FMB on the basis of
property additions and retired bonds under the terms of their respective
mortgage indentures. The issuance of FMB by OE is subject to a provision of its
senior note indenture generally limiting the incurrence of additional secured
debt, subject to certain exceptions that would permit, among other things, the
issuance of secured debt (including FMB) (i) supporting pollution control notes
or similar obligations, or (ii) as an extension, renewal or replacement of
previously outstanding secured debt. In addition, this provision would permit
OE to incur additional secured debt not otherwise permitted by a specified
exception of up to $639 million as of September 30, 2004. 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
September 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, of which $389 million was unused as of
September 30, 2004. These facilities are intended to provide liquidity to meet
the short-term working capital requirements of OE and its regulated affiliates. Borrowings under these facilities are conditioned on OE maintaining
compliance with certain financial covenants. 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 September 30, 2004, OEs fixed charge coverage
ratio, as defined under the credit agreements, was 7.36 to 1. OEs debt to
total capitalization ratio, as defined under the credit agreements, was 0.39 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 contain no provisions restricting its
ability to borrow, or accelerating repayment of outstanding loans, as a result
of any change in its 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. 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 third quarter of 2004 was 1.28%. 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 September 30, 2004 and matures on March 29,
2005. OE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 such securities is stable. 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-. On August 26, 2004, S&P stated that a favorable outcome of the Ohio Rate
Stabilization Plan auction process and a favorable resolution of pending
environmental litigation would support a higher ratings outlook, or possibly a
higher rating. S&P noted that a ratings upgrade in 2004 does not appear likely
because those major issues would most likely not be resolved before the end of
2004. On September 14, 2004, S&P stated that FirstEnergys $500 million
voluntary contribution to its pension plan was credit neutral. 71




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Cash Flows From Investing Activities Net cash used for investing activities totaled $190 million in the third
quarter of 2004 and $134 million provided from investing activities for the
first nine months of 2004, compared to net cash used for investing activities
of $241 million and $275 million, respectively, for the same periods of 2003.
The $51 million change for the third quarter and $409 million for the first
nine months, resulted primarily from $278 million of cash proceeds from
certificates of deposit in the third quarter of 2004. Loans to associated
companies increased $181 million in the third quarter of 2004 and decreased
$177 million first nine months, compared to the same periods in 2003. During the last quarter of 2004, capital requirements for property
additions and capital leases are expected to be about $78 million, including
$29 million for nuclear fuel. OE has additional requirements of approximately
$18 million to meet sinking fund requirements for preferred stock and maturing
long-term debt during the remainder of 2004. Those 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 September 30, 2004, the present value of these sale and
leaseback operating lease commitments, net of trust investments, total $696
million. Equity Price Risk Included in OEs nuclear decommissioning trust investments are marketable
equity securities carried at their market value of approximately $227 million
and $209 million as of September 30, 2004 and December 31, 2003, respectively.
A hypothetical 10% decrease in prices quoted by stock exchanges would result in
a $23 million reduction in fair value as of September 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 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 Companies filed an application with the PUCO
to establish generation service rates beginning January 1, 2006, in response to
expressed concerns by the PUCO about price and supply uncertainty following the
end of the market development period. The filing included two options:  
    
    A competitive auction, which would establish a price for
generation that customers would be charged during the period
covered by the auction, or  
    
    A Rate Stabilization Plan, which would extend current
generation prices through 2008, ensuring adequate generation
supply at stable prices, and continuing OEs support of energy
efficiency and economic development efforts. 72




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Under that proposal, OE requested:  
    
    Extension of the transition cost amortization period for
OE from 2006 to 2007;  
    
    Deferral of interest costs on the accumulated shopping
incentives and other cost deferrals as new regulatory assets;
and  
    
    Ability to initiate a request to increase generation
rates under certain limited conditions. On February 23, 2004, after consideration of the PUCO Staff comments and
testimony as well as those provided by some of the intervening parties, 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:  
    
    Limiting OEs ability to request adjustments in
generation charges during 2006 through 2008 to increases in
taxes;  
    
    Expanding the availability of market support generation;  
    
    Revising the kilowatt-hour target level and the time period for recovering regulatory transition charges;  
    
    Establishing a 3-year competitive bid process for generation;  
    
    Establishing the 2005 generation credit for shopping
customers, which would be extended as a cap through 2008; and  
    
    Denying the ability to defer costs for future recovery
of distribution reliability improvement expenditures. On June 18, 2004, OE filed with the PUCO an application for rehearing of
the modified version of the Rate Stabilization Plan. Several other parties also
filed applications for rehearing. On August 4, 2004, the PUCO issued an Entry
on Rehearing modifying its June 9, 2004 Order. The modifications included the
following:  
    
    Expanding 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;  
    
    Approving the revised kilowatt-hour target level and
time period for recovery of regulatory transition costs as
presented by OE in its rehearing application;  
    
    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;  
    
    Revising the calculation of the shopping credit cap for
certain commercial and small industrial rate schedules; and  
    
    Relaxing the notice requirement for availability of
enhanced shopping credits in a number of instances. On August 5, 2004, 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. On October 1,
2004, the OCC filed an appeal with the Ohio Supreme Court to overturn the June
9, 2004 PUCO order. 73




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OE filed a proposed competitive bid process which the PUCO modified on
October 6, 2004. The PUCO approved the rules for the competitive bid process
setting a three-year supply period (2006-2008) requirement for generation
service suppliers and a load cap for individual suppliers. In mid-October, the
initial auction schedule was revised so that Part 1 and Part 2 auction bidder
applications are due November 4 and November 15, 2004, respectively; the trial
auction is scheduled to occur on December 3; the auction would commence
December 8 and the PUCO will accept or reject the auction results within two
business days after the completion of the auction. FirstEnergy has elected not
to participate in the auction. 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. 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: Regulatory Assets as ofSeptember 30,
    
    December 31,2004
    
    2003(In millions)CompanyOE
    
    $
    1,184
    
    
    $
    1,450Penn
    
    
    
    *
    
    
    28Consolidated Total
    
    $
    1,184
    
    
    $
    1,478
  *
    
    Changes in Penns net regulatory asset components through September 30,
2004 resulted in net regulatory liabilities of approximately
$4 million included in
Other Noncurrent Liabilities on the Consolidated Balance Sheet
as of
September 30, 2004. Reliability Initiatives On October 15, 2003, NERC issued a letter to all NERC control areas and
reliability coordinators requesting a review of various reliability practices.
The Company response confirmed that its review was completed and that various
enhancements were underway to current practices. On February 10, 2004, NERC
issued its Recommended Actions to Prevent and Mitigate the Impacts of Future
Cascading Blackouts, a portion of which were directed at the FirstEnergy
companies and broadly focused on initiatives that were recommended for
completion by June 30, 2004. FirstEnergys detailed implementation plan was
endorsed by the NERC Board of Trustees on May 7, 2004. The various initiatives
recommended by NERC were certified as complete by June 30, 2004, with one minor
exception related to reactive testing of certain generators expected to be
completed later in 2004. On February 26 and 27, 2004, OE, as part of a NERC review of control area
operations throughout the United States, participated in a NERC Control Area
Readiness Audit. The final audit report, completed on May 6, 2004, identified
positive observations and included various recommendations for reliability
improvement. FirstEnergy reported completion of those recommendations on June
30, 2004, with one exception related to MISOs implementation of a voltage
stability tool expected to be completed later this year. On April 5, 2004, the U.S.  Canada Power System Outage Task Force issued
a Final Report on the August 14, 2003 power outages. The Final Report contains
46 recommendations to prevent or minimize the scope of future blackouts.
Forty-five of those recommendations relate to broad industry or policy matters
while one relates to activities the Task Force recommended be undertaken by
FirstEnergy, MISO, PJM and ECAR. FirstEnergy completed the Task Force
recommendations that were directed toward FirstEnergy and reported completion
of those activities on June 30, 2004. With respect to each of the foregoing initiatives, FirstEnergy requested
and NERC provided, a technical assistance team of experts to provide ongoing
guidance and assistance in implementing and confirming timely and successful
completion. NERC further assembled an independent verification team to confirm
implementation of the foregoing initiatives required to be completed as of June
30, 2004. The NERC Verification Team reported, on July 14, 2004, that
FirstEnergy has completed the recommended policies, procedures and actions
required to be completed by June 30, 2004 or summer 2004, with exceptions noted
by FirstEnergy. Implementation of the recommendations has not required
incremental material investment or upgrades to existing equipment. On March 1, 2004, OE 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. 74




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On April 22, 2004, FirstEnergy filed with the FERC the results of the
FERC-ordered independent study of part of Ohios power grid. The study
examined, among other things, the reliability of the transmission grid in
critical points in the Northern Ohio area and the need, if any, for reactive
power reinforcements during summers 2004 and 2009. Certain requested
additional clarifications were provided to the FERC in October 2004.
FirstEnergy completed the implementation of recommendations relating to 2004 by
June 30, 2004, and is continuing to review results related to 2009. The
estimated capital expenditures required by 2009 are not expected to have a
material adverse effect on FirstEnergys financial results. FirstEnergy notes,
however, that FERC or other applicable government agencies and reliability
coordinators may take a different view as to recommended enhancements or may
recommend additional enhancements in the future that could require additional,
material expenditures. In late 2003, the PPUC issued a Tentative Order implementing new
reliability benchmarks and standards. In connection therewith, the PPUC
commenced a rulemaking procedure to amend the Electric Service Reliability
Regulations to implement these new benchmarks, and required additional
reporting on reliability. The PPUC ordered all Pennsylvania utilities to begin
filing quarterly reports on November 1, 2003. On May 11, 2004, the PPUC issued
an order approving the revised reliability benchmark and standards, including
revised benchmarks and standards for Met-Ed, Penelec and Penn. The Order
permitted Pennsylvania utilities to file in a separate proceeding to revise the
recomputed benchmarks and standards if they have evidence, such as the impact
of automated outage management systems, on the accuracy of the PPUC computed
reliability indices. 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.
Hearings were held in early August 2004. On September 30, 2004, Penn filed a
settlement agreement with the PPUC that addresses the issues related to this
investigation. As part of the settlement, Penn agreed to enhance service
reliability, performance reporting and communications with customers and
together with Met-Ed and Penelec, to collectively maintain their current
spending levels of at least $255 million annually on combined capital and
operation and maintenance expenditures for transmission and distribution for
the years 2005 through 2007. In November 2004, the PPUC accepted the
recommendation of the ALJ approving the settlement. 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 NOV or a Compliance Orders 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 75




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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 September 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
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. SIPs 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 requires 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. On September 7, 2004, the EPA established new performance standards under
Clean Water Act Section 316(b) for reducing impacts on fish and shellfish from
cooling water intake structures at certain existing large electric generating
plants. The regulations call for reductions in impingement mortality, when
aquatic organisms are pinned against screens or other parts of a cooling water
intake system and entrainment, which occurs when aquatic species are drawn into
a facilitys cooling water system. The OE Companies are conducting
comprehensive demonstration studies, due in 2008, to determine the operational
measures, equipment or restoration activities, if any, necessary for compliance
by their facilities with the performance standards. The OE Companies are
unable to predict the outcome of such studies. Depending on the outcome of
such studies, the future cost of compliance with these standards may be
substantial. Power Outages and Related Litigation On August 14, 2003, various states and parts of southern Canada
experienced widespread power outages. The outages affected approximately 1.4
million customers in FirstEnergys service area. On April 5, 2004, the U.S.
Canada Power System Outage Task Force released its final report on the
outages. In the final report, the Task Force concluded, among other things,
that the problems leading to the outages began in FirstEnergys Ohio service
area. Specifically, the final report concludes, among other things, that the
initiation of the August 14, 2003 power outages resulted from an alleged
failure of both FirstEnergy and ECAR to assess and understand perceived
inadequacies within the FirstEnergy system; inadequate situational awareness of
the developing conditions; and a perceived failure to adequately manage tree
growth in certain transmission rights of way. The Task Force also concluded
that there was a failure of the interconnected grids reliability organizations
(MISO and PJM) to provide effective diagnostic support. The final report is
publicly available through the Department of Energys website (www.doe.gov).
FirstEnergy believes that the final report does not provide a complete and
comprehensive picture of the conditions that contributed to the August 14, 2003
power outages and that it does not adequately address the underlying causes of
the outages. FirstEnergy remains convinced that the outages cannot be explained
by events on any one utilitys system. The final report contains 46
recommendations to prevent or minimize the scope of future blackouts.
Forty-five of those recommendations relate to broad industry or policy matters
while one, including subparts, relates to activities the Task Force recommends
be undertaken by FirstEnergy, MISO, PJM, and ECAR. FirstEnergy implemented
several initiatives, both prior to and since the August 14, 2003 power outages,
which are consistent with these and other recommendations and collectively
enhance the reliability of its electric system. FirstEnergy certified to NERC
on June 30, 2004, completion of various reliability recommendations and further
received independent verification of completion status from a NERC verification
team on July 14, 2004 (see 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 September 30, 2004 for any expenditures in excess of
those actually incurred through that date. Three substantially similar actions were filed in various Ohio state
courts by plaintiffs seeking to represent customers who allegedly suffered
damages as a result of the August 14, 2003 power outages. All three cases were
dismissed for lack of jurisdiction. One case was refiled at the PUCO and the
other two have been appealed. In addition to the one case that was refiled at
the PUCO, the Ohio Companies were named as respondents in a regulatory
proceeding that was initiated at the PUCO in response to complaints alleging
failure to provide reasonable and adequate service stemming primarily from the
August 14, 2003 power outages. 76




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One complaint has been filed against FirstEnergy in the New York State
Supreme Court. In this case, several plaintiffs in the New York City
metropolitan area allege that they suffered damages as a result of the August
14, 2003 power outages. None of the plaintiffs are customers of any
FirstEnergy affiliate. FirstEnergy filed a motion to dismiss with the Court on
October 22, 2004. No damage estimate has been provided and thus potential
liability has not been determined. FirstEnergy is vigorously defending these actions, but cannot predict the
outcome of any of these proceedings or whether any further regulatory
proceedings or legal actions may be instituted against the Companies. In
particular, if FirstEnergy or its subsidiaries were ultimately determined to
have legal liability in connection with these proceedings, it could have a
material adverse effect on FirstEnergys or its subsidiaries financial
condition and results of operations. Legal Matters Various lawsuits, claims (including claims for asbestos exposure) and
proceedings related to OEs normal business operations are pending against OE
and its subsidiaries. The most significant not otherwise discussed above are
described below. On August 12, 2004, the NRC publicly disclosed that it was notifying
FirstEnergy that it will increase its regulatory oversight of the Perry Nuclear
Power Plant as a result of problems with safety system equipment over the past
two years. The OE Companies have a 35.24% interest in the Perry Nuclear Power
Plant. The NRC noted that the plant continues to operate safely. The increased
oversight will include an extensive NRC team inspection to access the equipment
problems and FirstEnergys corrective actions. The outcome of this increased
oversight is not known at this time. On October 20, 2004, FirstEnergy was notified by the SEC that the
previously disclosed informal inquiry initiated by the SECs Division of
Enforcement in September 2003 relating to the restatements in August 2003 of
previously reported results by FirstEnergy and OE and the Davis-Besse extended
outage (OE has no interest in Davis-Besse) has become the subject of a formal
order of investigation. The SECs formal order of investigation also
encompasses issues raised during the SECs examination of FirstEnergy and the
Companies under the PUHCA. Concurrent with this notification, FirstEnergy
received a subpoena asking for background documents and documents related to
the restatements and Davis-Besse issues. FirstEnergy has cooperated fully with
the informal inquiry and will continue to do so with the formal investigation. If it were ultimately determined that FirstEnergy or its subsidiaries has
legal liability or is otherwise made subject to liability based on any of the
above matters, it could have a material adverse effect on FirstEnergys or its
subsidiaries financial condition and results of operations. 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. 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, demand by customer class, weather-related impacts and electricity
provided by alternative suppliers. 77




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Pension and Other Postretirement Benefits Accounting FirstEnergys
pension and postretirement 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 in the first
nine months 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. In the third quarter of 2004, FirstEnergy made a $500 million voluntary
contribution to its pension plan ($73 million funded by the OE Companies). This
contribution will mitigate future funding requirements and significantly reduce
the year-end minimum pension liability that currently reduces the OE Companies
accumulated other comprehensive income by $62 million. 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
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). 78




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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 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 In March 2004, the EITF reached a consensus on the application guidance
for Issue 03-1. EITF 03-1 provides a model for determining when investments in
certain debt and equity securities are considered other than temporarily
impaired. When an impairment is other-than-temporary, the investment must be
measured at fair value and the impairment loss recognized in earnings. The
recognition and measurement provisions of EITF 03-1, which were to be effective
for periods beginning after June 15, 2004, were delayed by the issuance of FSP
EITF 03-1-1 in September 2004. During the period of delay, OE will continue to
evaluate its investments as required by existing authoritative guidance. 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 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, 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. 79




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THE CLEVELAND ELECTRIC ILLUMINATING COMPANY 
 CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited) Three Months Ended
    
    Nine Months EndedSeptember 30,
    
    September 30,2004
    
    2003
    
    2004
    
    2003(In thousands)STATEMENTS OF INCOMEOPERATING REVENUES
    
    $
    504,848
    
    
    $
    496,110
    
    
    $
    1,372,259
    
    
    $
    1,328,014OPERATING EXPENSES AND TAXES:Fuel
    
    
    21,011
    
    
    
    5,536
    
    
    
    57,583
    
    
    
    30,117Purchased power
    
    
    140,988
    
    
    
    139,661
    
    
    
    412,170
    
    
    
    407,261Nuclear operating costs
    
    
    28,766
    
    
    
    67,449
    
    
    
    80,002
    
    
    
    190,028Other operating costs
    
    
    76,196
    
    
    
    64,370
    
    
    
    219,857
    
    
    
    192,128Provision for depreciation and amortization
    
    
    46,232
    
    
    
    42,443
    
    
    
    157,850
    
    
    
    147,111General taxes
    
    
    37,348
    
    
    
    37,689
    
    
    
    110,646
    
    
    
    114,741Income taxes
    
    
    51,883
    
    
    
    38,719
    
    
    
    81,057
    
    
    
    47,827Total operating expenses and taxes
    
    
    402,424
    
    
    
    395,867
    
    
    
    1,119,165
    
    
    
    1,129,213OPERATING INCOME
    
    
    102,424
    
    
    
    100,243
    
    
    
    253,094
    
    
    
    198,801OTHER INCOME
    
    
    8,264
    
    
    
    6,196
    
    
    
    29,485
    
    
    
    15,621NET INTEREST CHARGES:Interest on long-term debt
    
    
    24,061
    
    
    
    38,130
    
    
    
    92,967
    
    
    
    118,069Allowance for borrowed funds used during construction
    
    
    (1,056
    )
    
    
    (1,920
    )
    
    
    (3,782
    )
    
    
    (5,724
    )Other interest expense
    
    
    5,239
    
    
    
    163
    
    
    
    12,750
    
    
    
    199Subsidiaries preferred stock dividend requirements
    
    
    
    
    
    
    2,250
    
    
    
    
    
    
    
    9,450Net interest charges
    
    
    28,244
    
    
    
    38,623
    
    
    
    101,935
    
    
    
    121,994INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING
CHANGE
    
    
    82,444
    
    
    
    67,816
    
    
    
    180,644
    
    
    
    92,428Cumulative effect of accounting change (net of income taxes
of $30,168,000) (Note 2)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    42,378NET INCOME
    
    
    82,444
    
    
    
    67,816
    
    
    
    180,644
    
    
    
    134,806PREFERRED STOCK DIVIDEND REQUIREMENTS
    
    
    1,754
    
    
    
    1,865
    
    
    
    5,253
    
    
    
    2,970EARNINGS ON COMMON STOCK
    
    $
    80,690
    
    
    $
    65,951
    
    
    $
    175,391
    
    
    $
    131,836STATEMENTS OF COMPREHENSIVE INCOMENET INCOME
    
    $
    82,444
    
    
    $
    67,816
    
    
    $
    180,644
    
    
    $
    134,806OTHER COMPREHENSIVE INCOME (LOSS):Minimum liability for unfunded retirement benefits
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    24,171Unrealized gain (loss) on available for sale securities
    
    
    991
    
    
    
    3,873
    
    
    
    (1,332
    )
    
    
    22,826Other comprehensive income (loss)
    
    
    991
    
    
    
    3,873
    
    
    
    (1,332
    )
    
    
    46,997Income tax related to other comprehensive income
    
    
    (406
    )
    
    
    (1,611
    )
    
    
    546
    
    
    
    (19,774
    )Other comprehensive income (loss), net of tax
    
    
    585
    
    
    
    2,262
    
    
    
    (786
    )
    
    
    27,223TOTAL COMPREHENSIVE INCOME
    
    $
    83,029
    
    
    $
    70,078
    
    
    $
    179,858
    
    
    $
    162,029
 The preceding Notes to Consolidated Financial Statements as they relate to The
Cleveland Electric Illuminating Company are an integral part of these
statements. 80




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THE CLEVELAND ELECTRIC ILLUMINATING COMPANY 
 CONSOLIDATED BALANCE SHEETS
(Unaudited) September 30,
    
    December 31,2004
    
    2003(In thousands)ASSETSUTILITY PLANT:In service
    
    $
    4,383,939
    
    
    $
    4,232,335Less-Accumulated provision for depreciation
    
    
    1,941,362
    
    
    
    1,857,5882,442,577
    
    
    
    2,374,747Construction work in progress-Electric plant
    
    
    100,729
    
    
    
    159,897Nuclear fuel
    
    
    9,634
    
    
    
    21,338110,363
    
    
    
    181,2352,552,940
    
    
    
    2,555,982OTHER PROPERTY AND INVESTMENTS:Investment in lessor notes
    
    
    596,649
    
    
    
    605,915Nuclear plant decommissioning trusts
    
    
    345,303
    
    
    
    313,621Long-term notes receivable from associated companies
    
    
    97,830
    
    
    
    107,946Other
    
    
    17,066
    
    
    
    23,6361,056,848
    
    
    
    1,051,118CURRENT ASSETS:Cash and cash equivalents
    
    
    200
    
    
    
    24,782Receivables-Customers
    
    
    13,196
    
    
    
    10,313Associated companies
    
    
    13,076
    
    
    
    40,541Other (less accumulated provisions of $844,000 and $1,765,000, respectively,
for uncollectible accounts)
    
    
    103,340
    
    
    
    185,179Notes receivable from associated companies
    
    
    634
    
    
    
    482Materials and supplies, at average cost
    
    
    58,327
    
    
    
    50,616Prepayments and other
    
    
    1,102
    
    
    
    4,511189,875
    
    
    
    316,424DEFERRED CHARGES:Regulatory assets
    
    
    982,626
    
    
    
    1,056,050Goodwill
    
    
    1,693,629
    
    
    
    1,693,629Property taxes
    
    
    77,122
    
    
    
    77,122Other
    
    
    26,674
    
    
    
    23,1232,780,051
    
    
    
    2,849,924$
    6,579,714
    
    
    $
    6,773,448CAPITALIZATION AND LIABILITIESCAPITALIZATION:Common stockholders equity-Common stock, without par value, authorized 105,000,000 shares-
79,590,689 shares outstanding
    
    $
    1,281,962
    
    
    $
    1,281,962Accumulated other comprehensive income
    
    
    1,867
    
    
    
    2,653Retained earnings
    
    
    524,607
    
    
    
    494,212Total common stockholders equity
    
    
    1,808,436
    
    
    
    1,778,827Preferred stock not subject to mandatory redemption
    
    
    96,404
    
    
    
    96,404Long-term debt and other long-term obligations
    
    
    1,975,324
    
    
    
    1,884,6433,880,164
    
    
    
    3,759,874CURRENT LIABILITIES:Currently payable long-term debt
    
    
    76,690
    
    
    
    387,414Accounts payable-Associated companies
    
    
    245,672
    
    
    
    245,815Other
    
    
    9,374
    
    
    
    7,342Notes payable to associated companies
    
    
    331,140
    
    
    
    188,156Accrued taxes
    
    
    150,027
    
    
    
    202,522Accrued interest
    
    
    35,501
    
    
    
    37,872Lease market valuation liability
    
    
    60,200
    
    
    
    60,200Other
    
    
    36,292
    
    
    
    76,722944,896
    
    
    
    1,206,043NONCURRENT LIABILITIES:Accumulated deferred income taxes
    
    
    498,920
    
    
    
    486,048Accumulated deferred investment tax credits
    
    
    62,202
    
    
    
    65,996Asset retirement obligation
    
    
    267,693
    
    
    
    254,834Retirement benefits
    
    
    84,284
    
    
    
    105,101Lease market valuation liability
    
    
    683,300
    
    
    
    728,400Other
    
    
    158,255
    
    
    
    167,1521,754,654
    
    
    
    1,807,531COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 3)$
    6,579,714
    
    
    $
    6,773,448
 The preceding Notes to Consolidated Financial Statements as they relate to The
Cleveland Electric Illuminating Company are an integral part of these balance
sheets. 81




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THE CLEVELAND ELECTRIC ILLUMINATING COMPANY 
 CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited) Three Months Ended
    
    Nine Months EndedSeptember 30,
    
    September 30,2004
    
    2003
    
    2004
    
    2003(In thousands)CASH FLOWS FROM OPERATING ACTIVITIES:Net income
    
    $
    82,444
    
    
    $
    67,816
    
    
    $
    180,644
    
    
    $
    134,806Adjustments to reconcile net income to net
cash from operating activities-Provision for depreciation and amortization
    
    
    46,232
    
    
    
    42,443
    
    
    
    157,850
    
    
    
    147,111Nuclear fuel and capital lease amortization
    
    
    7,804
    
    
    
    4,178
    
    
    
    20,420
    
    
    
    12,217Other amortization
    
    
    (3,336
    )
    
    
    (7,911
    )
    
    
    (12,877
    )
    
    
    (12,933
    )Deferred operating lease costs, net
    
    
    (14,324
    )
    
    
    (36,167
    )
    
    
    (56,182
    )
    
    
    (77,992
    )Deferred income taxes, net
    
    
    14,320
    
    
    
    14,847
    
    
    
    15,186
    
    
    
    48,784Amortization of investment tax credits
    
    
    (1,301
    )
    
    
    (1,202
    )
    
    
    (3,794
    )
    
    
    (3,605
    )Accrued retirement benefit obligations
    
    
    2,854
    
    
    
    26,453
    
    
    
    10,900
    
    
    
    10,566Accrued compensation, net
    
    
    1,303
    
    
    
    257
    
    
    
    3,232
    
    
    
    (4,056
    )Cumulative effect of accounting change (Note 2)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (72,546
    )Pension trust contribution
    
    
    (31,718
    )
    
    
    
    
    
    
    (31,718
    )
    
    
    Receivables
    
    
    (3,422
    )
    
    
    234,672
    
    
    
    106,421
    
    
    
    86,460Materials and supplies
    
    
    (2,238
    )
    
    
    (2,164
    )
    
    
    (7,711
    )
    
    
    8,647Prepayments and other current assets
    
    
    1,512
    
    
    
    (479
    )
    
    
    3,409
    
    
    
    714Accounts payable
    
    
    60,237
    
    
    
    (235,048
    )
    
    
    1,889
    
    
    
    (55,802
    )Accrued taxes
    
    
    (15,630
    )
    
    
    46,327
    
    
    
    (52,495
    )
    
    
    33,765Accrued interest
    
    
    (3,218
    )
    
    
    7,996
    
    
    
    (2,371
    )
    
    
    4,428Other
    
    
    (10,010
    )
    
    
    (36,610
    )
    
    
    (40,193
    )
    
    
    (5,882
    )Net cash provided from operating activities
    
    
    131,509
    
    
    
    125,408
    
    
    
    292,610
    
    
    
    254,682CASH FLOWS FROM FINANCING ACTIVITIES:New Financing-Long-term debt
    
    
    44,330
    
    
    
    
    
    
    
    125,238
    
    
    
    Short-term borrowings, net
    
    
    213,682
    
    
    
    
    
    
    
    132,770
    
    
    
    Redemptions and Repayments-Preferred Stock
    
    
    (1,000
    )
    
    
    (1,000
    )
    
    
    (1,000
    )
    
    
    (1,093
    )Long-term debt
    
    
    (327,171
    )
    
    
    (256
    )
    
    
    (335,272
    )
    
    
    (146,321
    )Short-term borrowings, net
    
    
    
    
    
    
    (123,711
    )
    
    
    
    
    
    
    (73,490
    )Dividend Payments-Common stock
    
    
    
    
    
    
    
    
    
    
    (145,000
    )
    
    
    Preferred stock
    
    
    (1,755
    )
    
    
    (1,864
    )
    
    
    (5,253
    )
    
    
    (5,594
    )Net cash used for financing activities
    
    
    (71,914
    )
    
    
    (126,831
    )
    
    
    (228,517
    )
    
    
    (226,498
    )CASH FLOWS FROM INVESTING ACTIVITIES:Property additions
    
    
    (32,238
    )
    
    
    (29,620
    )
    
    
    (70,967
    )
    
    
    (91,643
    )Loan repayments from (loans to) associated companies, net
    
    
    (850
    )
    
    
    (5,574
    )
    
    
    9,964
    
    
    
    (5,354
    )Investments in lessor notes
    
    
    (11,699
    )
    
    
    30,891
    
    
    
    9,266
    
    
    
    49,962Contributions to nuclear decommissioning trusts
    
    
    (7,256
    )
    
    
    (14,512
    )
    
    
    (21,768
    )
    
    
    (21,768
    )Other
    
    
    (7,552
    )
    
    
    20,238
    
    
    
    (15,170
    )
    
    
    10,396Net cash provided from (used for) investing activities
    
    
    (59,595
    )
    
    
    1,423
    
    
    
    (88,675
    )
    
    
    (58,407
    )Net change in cash and cash equivalents
    
    
    
    
    
    
    
    
    
    
    (24,582
    )
    
    
    (30,223
    )Cash and cash equivalents at beginning of period
    
    
    200
    
    
    
    159
    
    
    
    24,782
    
    
    
    30,382Cash and cash equivalents at end of period
    
    $
    200
    
    
    $
    159
    
    
    $
    200
    
    
    $
    159
 The preceding Notes to Consolidated Financial Statements as they relate to The
Cleveland Electric Illuminating Company are an integral part of these
statements. 82




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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 September 30, 2004,
and the related consolidated statements of income, comprehensive income and
cash flows for each of the three-month and nine-month periods ended September
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
November 2, 2004 83




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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 CEI as their power supplier. CEI provides power directly to
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 third quarter of 2004 increased to $81
million from $66 million in the third quarter of 2003. For the first nine
months of 2004, earnings on common stock increased to $175 million from $132
million in the same period of 2003. Earnings on common stock in the first nine
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 $92 million in the first nine months of 2003.
Increased earnings in both 2004 periods resulted principally from higher
operating revenues, lower nuclear operating costs and reduced interest charges
 partially offset by higher fuel and other operating costs compared to 2003.
Revenues for both periods were higher due to significant increases in sales to
FES. Lower nuclear operating costs in the third quarter and the first nine
months of 2004, compared with the same periods of 2003, were due to reduced
incremental maintenance costs associated with the Davis-Besse extended outage
and the absence of nuclear refueling outages at Beaver Valley Unit 2 and the
Perry Plant in 2003. Lower net interest charges in the third quarter and the
first nine months of 2004, compared with the same periods of 2003, were
primarily due to debt redemptions and refinancing activities. Operating revenues increased by $9 million or 1.8% in the third quarter
from the same period of 2003. Higher revenues resulted principally from a $39
million (49.5%) increase in wholesale sales (primarily to FES) due to increased
nuclear generation available for sale which was partially offset by reduced
generation sales revenue from franchise customers of $8 million. The reduction
in retail generation revenues (residential  $4 million and commercial  $2
million) in the third quarter of 2004 reflected increases in electric
generation services to residential and commercial customers provided by
alternative suppliers as a percent of total sales deliveries in CEIs franchise
area of 4.6 percentage points and 7.6 percentage points, respectively while the
corresponding percentage for industrial customers decreased by 4.3 percentage
points. Lower industrial sales unit prices offset the impact of an increase in
kilowatt-hour sales to industrial customers. In the first nine months of 2004,
operating revenues increased by $44 million (3.3%) primarily as a result of a
$96 million increase in wholesale revenues (primarily to FES) due to increased
available nuclear generation in the first nine months of 2004. The increase in
wholesale revenues was partially offset by a 2.8% decrease in retail generation
sales, which resulted in lower revenues of $19 million. Decreased retail
generation revenues in the first nine months of 2004 reflected the same trend
in shopping for generation providers (increases of 7.4 and 9.1 percentage
points for residential and commercial customers, respectively, and a decrease
of 3.7 percentage points for industrial customers). Residential and commercial
revenues decreased due to lower kilowatt-hour sales and unit prices that were
partially offset by an increase in revenue from higher industrial generation
sales. The higher industrial revenues resulted from increased sales that were
partially offset by lower unit prices. Revenues from distribution throughput decreased by $22 million and $27
million in the third quarter and first nine months of 2004, respectively, as
compared to the same periods of 2003, even though total distribution deliveries
were nearly unchanged in the third quarter and increased 0.7% in the first nine
months of 2004. Distribution deliveries to residential customers decreased 8.0%
in the third quarter and 3.7% in the first nine months of 2004 resulting from
cooler weather in the third quarter of 2004 as compared to the same quarter of
2003 which reduced air conditioning loads. An improving economy increased
distribution deliveries to commercial and industrial customers in the third
quarter and first nine months of 2004. Lower unit prices in all customer
sectors for both periods offset the effect of higher distribution deliveries to
commercial and industrial customers. Under the Ohio transition plan, CEI provides incentives to customers to
encourage switching to alternative energy providers  $2 million of additional
credits in the third quarter and $6 million of additional credits in the first
nine months of 2004 compared with the corresponding periods of 2003. 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
third quarter and first nine months of 2004 from the corresponding periods of
2003 are summarized in the following table: 84




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Changes in KWH Sales
    
    Three Months
    
    Nine MonthsIncrease (Decrease)Electric Generation:Retail
    
    
    (1.1
    )%
    
    
    (2.8
    )%Wholesale
    
    
    46.6
    %
    
    
    39.7
    %Total Electric Generation Sales
    
    
    23.2
    %
    
    
    17.8
    %Distribution Deliveries:Residential
    
    
    (8.0
    )%
    
    
    (3.7
    )%Commercial
    
    
    3.3
    %
    
    
    1.6
    %Industrial
    
    
    2.8
    %
    
    
    2.9
    %Total Distribution Deliveries
    
    
    (0.1
    )%
    
    
    0.7
    %
 Operating Expenses and Taxes Total operating expenses and taxes increased by $7 million in the third
quarter of 2004 from the third quarter of 2003 and decreased by $10 million in
the first nine months of 2004 from the first nine months of 2003. The following
table presents changes from the prior year by expense category. Operating Expenses and Taxes  Changes
    
    Three Months
    
    Nine Months(In millions)Increase (Decrease)Fuel
    
    $
    15
    
    
    $
    27Purchased power
    
    
    1
    
    
    
    5Nuclear operating costs
    
    
    (38
    )
    
    
    (110
    )Other operating costs
    
    
    12
    
    
    
    28Total operation and maintenance expenses
    
    
    (10
    )
    
    
    (50
    )Provision for depreciation and amortization
    
    
    4
    
    
    
    11General taxes
    
    
    
    
    
    
    (4
    )Income taxes
    
    
    13
    
    
    
    33Total operating expenses and taxes
    
    $
    7
    
    
    $
    (10
    )
 Higher fuel costs in the third quarter and first nine months of 2004,
compared with the same periods of 2003, resulted principally from the increased
nuclear generation. Higher purchased power costs in the first nine months of
2004 compared with the same time period of 2003 reflect higher unit costs,
partially offset by lower kilowatt-hours purchased. The decrease in nuclear
operating costs for both periods were due to reduced incremental costs
associated with the Davis-Besse extended outage and work performed during the
Perry plant 56-day refueling outage (44.85% ownership) in the second quarter of
2003 and the Beaver Valley Unit 2 refueling outage (24.47% ownership) in the
third quarter of 2003. Other operating costs increased in the third quarter and
first nine months of 2004, compared to the same periods of 2003, in part from
higher employee benefit costs. The increase in depreciation and amortization charges in the third quarter
of 2004, compared with the third quarter of 2003, was primarily due to higher
amortization of regulatory assets ($10 million), partially offset by higher
shopping incentive deferrals ($2 million) and deferred interest on the shopping
incentives (see Regulatory Matters) in the third quarter of 2004 ($4 million).
The increase in depreciation and amortization charges in the first nine months
of 2004, compared with the first nine months of 2003 was primarily due to
increased amortization of regulatory assets ($26 million), partially offset by
higher shopping incentive deferrals ($6 million) and deferred interest on the
shopping incentives ($12 million). General taxes decreased in the first nine months of 2004, compared to the
same period last year, reflecting in part a $2 million refund received on a
real estate valuation settlement. Other Income Other income increased by $2 million in the third quarter and $14 million
in the first nine 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 $10 million
in the third quarter and $20 million in the first nine months of 2004 from the
same periods last year, reflecting redemptions and refinancings since the end
of the third quarter of 2003. CEIs long-term debt redemptions of $289 million
during the first nine months of 2004 are expected to result in annualized
savings of approximately $26 million. 85




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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 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
nine 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 September 30, 2004, CEI had $200,000 of cash and cash equivalents,
compared with $25 million as of December 31, 2003. The major sources of changes
in these balances are summarized below. Cash Flows From Operating Activities Cash provided by operating activities during the third quarter and first
nine months of 2004, compared with the corresponding periods in 2003, were as
follows: Three Months Ended
    
    Nine Months EndedSeptember 30,
    
    September 30,Operating Cash Flows
    
    2004
    
    2003
    
    2004
    
    2003(In millions)Cash earnings(1)
    
    $
    136
    
    
    $
    110
    
    
    $
    315
    
    
    $
    182Pension trust contribution
    
    
    (32
    )
    
    
    
    
    
    
    (32
    )
    
    
    Working capital and other
    
    
    28
    
    
    
    16
    
    
    
    10
    
    
    
    73Total
    
    $
    132
    
    
    $
    126
    
    
    $
    293
    
    
    $
    255
  (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 $6 million in the
third quarter of 2004 from the third quarter of 2003 as a result of a $26
million increase in cash earnings as described above under Results of
Operations and an $12 million increase from changes in working capital,
partially offset by a voluntary pension trust contribution of $32 million. The
largest factor contributing to the increase in working capital was an increase
in accounts payable partially offset by a decrease in receivables. Net cash
provided from operating activities, increased $38 million in the first nine
months of 2004 compared to the same period last year as a result of a $133
million increase in cash earnings, partially offset by a $63 million reduction
from changes in working capital and the $32 million pension contribution. The
change in working capital was principally due to a decrease in accrued taxes
partially offset by an increase in accounts payable. The increase in cash
earnings reflects the favorable impact of reduced nuclear operating costs and
lower interest charges in 2004. Cash Flows From Financing Activities Net cash used for financing activities decreased by $55 million in the
third quarter of 2004 from the third quarter of 2003. The decrease in funds
used for financing activities resulted from an increase in short-term
borrowings in 2004 to finance a portion of debt redemptions. Net cash used for
financing activities increased $2 million in the first nine months of 2004 from
the same period last year. The increase resulted from a $145 million increase
in common stock dividends to FirstEnergy, nearly offset by a $143 million
reduction in net debt redemptions. CEI had about $0.8 million of cash and temporary investments (which
include short-term notes receivable from associated companies) and
approximately $331 million of short-term indebtedness as of September 30, 2004.
CEI has obtained authorization from the PUCO to incur short-term debt of up to
$500 million (including the utility money pool 86




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described below). CEI had the capability to issue $1.4 billion of additional
first mortgage bonds on the basis of property additions and retired bonds under
the terms of its mortgage indenture. The issuance of FMB by CEI is subject to a
provision of its senior note indenture generally limiting the incurrence of
additional secured debt, subject to certain exceptions that would permit, among
other things, the issuance of secured debt (including FMB) (i) supporting
pollution control notes or similar obligations, or (ii) as an extension,
renewal or replacement of previously outstanding secured debt. In addition,
this provision would permit CEI to incur additional secured debt not otherwise
permitted by a specified exception of up to $582 million as of September 30,
2004. 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
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 third quarter of 2004 was 1.28%. On September 2, 2004 and October 1, 2004, Ohio Water Development Authority
pollution control notes aggregating $46.1 million and $23.3 million,
respectively, were refunded. The new notes were issued in a Dutch Auction
interest rate mode, insured by a municipal bond insurance policy and secured by
FMBs. CEI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 such securities is stable. On August 26, 2004, S&P stated that a favorable outcome of the Ohio Rate
Stabilization Plan auction process and a favorable resolution of pending
environmental litigation would support a higher ratings outlook, or possibly a
higher rating. S&P noted that a ratings upgrade in 2004 does not appear likely
because those major issues would most likely not be resolved before the end of
2004. On September 14, 2004, S&P stated that FirstEnergys $500 million
voluntary contribution to its pension plan was credit neutral. Cash Flows From Investing Activities In the third quarter and first nine months of 2004, net cash used for
investing activities increased $61 million and $30 million, respectively, from
the corresponding periods of 2003. The increase in cash used for investing
activities primarily reflected increases in net cash used for investments in
lessor notes. During the fourth quarter of 2004, capital requirements for property
additions are expected to be about $59 million, including $30 million for
nuclear fuel. CEI has no 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 September 30, 2004, the present value of these sale and leaseback
operating lease commitments, net of trust investments, total $113 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 $131 million
of off-balance sheet financing as of September 30, 2004. As of September 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 $214 million
and $188 million as of September 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 September 30, 2004. 87




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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. 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 Companies filed an application with the PUCO
to establish generation service rates beginning January 1, 2006, in response to
expressed concerns by the PUCO about price and supply uncertainty following the
end of the market development period. The filing included two options:  
    
    A competitive auction, which would establish a price for
generation that customers would be charged during the period
covered by the auction, or  
    
    A Rate Stabilization Plan, which would extend current
generation prices through 2008, ensuring adequate generation
supply at stable prices, and continuing CEIs support of energy
efficiency and economic development efforts. Under that proposal, CEI requested:  
    
    Extension of the transition cost amortization period for
CEI from 2008 to 2009;  
    
    Deferral of interest costs on the accumulated shopping
incentives and other cost deferrals as new regulatory assets;
and  
    
    Ability to initiate a request to increase generation
rates under certain limited conditions. On February 23, 2004, after consideration of the PUCO Staff comments and
testimony as well as those provided by some of the intervening parties, 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:  
    
    Limiting the ability of CEI to request adjustments in
generation charges during 2006 through 2008 for increases in
taxes;  
    
    Expanding the availability of market support generation;  
    
    Revising the kilowatt-hour target level and the time period for recovering regulatory transition charges;  
    
    Establishing a 3-year competitive bid process for generation;  
    
    Establishing the 2005 generation credit for shopping
customers, which would be extended as a cap through 2008; and  
    
    Denying the ability to defer costs for future recovery
of distribution reliability improvement expenditures. 88




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On June 18, 2004, 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:  
    
    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;  
    
    Approving the revised kilowatt-hour target level and
time period for recovery of regulatory transition costs as
presented by CEI in its rehearing application;  
    
    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;  
    
    Revising the calculation of the shopping credit cap for
certain commercial and small industrial rate schedules; and  
    
    Relaxing the notice requirement for availability of
enhanced shopping credits in a number of instances. On August 5, 2004, 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. On October
1, 2004, the OCC filed an appeal with the Ohio Supreme Court to overturn the
June 9, 2004 PUCO order. CEI filed a proposed competitive bid process which the PUCO modified on
October 6, 2004. The PUCO approved the rules for the competitive bid process
setting a three-year supply period (2006-2008) requirement for generation
service suppliers and a load cap for individual suppliers. In mid-October, the
initial auction schedule was revised so that Part 1 and Part 2 auction bidder
applications are due November 4 and November 15, 2004, respectively; the trial
auction is scheduled to occur on December 3; the auction would commence
December 8 and the PUCO will accept or reject the auction results within two
business days after the completion of the auction. FirstEnergy has elected not
to participate in the auction. 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 September 30, 2004 and December 2003 were $1.0 billion
and $1.1 billion, respectively. Reliability Initiatives On October 15, 2003, NERC issued a letter to all NERC control areas and
reliability coordinators requesting a review of various reliability practices.
The Company response confirmed that its review was completed and that various
enhancements were underway to current practices. On February 10, 2004, NERC
issued its Recommended Actions to Prevent and Mitigate the Impacts of Future
Cascading Blackouts, a portion of which were directed at the FirstEnergy
companies and broadly focused on initiatives that were recommended for
completion by June 30, 2004. FirstEnergys detailed implementation plan was
endorsed by the NERC Board of Trustees on May 7, 2004. The various initiatives
recommended by NERC were certified as complete by June 30, 2004, with one minor
exception related to reactive testing of certain generators expected to be
completed later in 2004. On February 26 and 27, 2004, CEI, as part of a NERC review of control area
operations throughout the United States, participated in a NERC Control Area
Readiness Audit. The final audit report, completed on May 6, 2004, identified
positive observations and included various recommendations for reliability
improvement. FirstEnergy reported completion of those recommendations on June
30, 2004, with one exception related to MISOs implementation of a voltage
stability tool expected to be completed later this year. On April 5, 2004, the U.S.  Canada Power System Outage Task Force issued
a Final Report on the August 14, 2003 power outages. The Final Report contains
46 recommendations to prevent or minimize the scope of future blackouts.
Forty-five of those recommendations relate to broad industry or policy matters
while one relates to 89




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##### Table of Contents



activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM
and ECAR. FirstEnergy completed the Task Force recommendations that were
directed toward FirstEnergy and reported completion of those activities on June
30, 2004. With respect to each of the foregoing initiatives, FirstEnergy requested
and NERC provided, a technical assistance team of experts to provide ongoing
guidance and assistance in implementing and confirming timely and successful
completion. NERC further assembled an independent verification team to confirm
implementation of the foregoing initiatives required to be completed as of June
30, 2004. The NERC Verification Team reported, on July 14, 2004, that
FirstEnergy has completed the recommended policies, procedures and actions
required to be completed by June 30, 2004 or summer 2004, with exceptions noted
by FirstEnergy. Implementation of the recommendations has not required
incremental material investment or upgrades to existing equipment. On March 1, 2004, CEI filed, in accordance with a November 25, 2003 order
from the PUCO, their plan for addressing certain issues identified by the PUCO
from the U.S.  Canada Power System Outage Task Force interim report. In
particular, the filing addressed upgrades to FirstEnergys control room
computer hardware and software and enhancements to the training of control room
operators. The PUCO will review the plan before determining the next steps, if
any, in the proceeding. On April 22, 2004, FirstEnergy filed with the FERC the results of the
FERC-ordered independent study of part of Ohios power grid. The study
examined, among other things, the reliability of the transmission grid in
critical points in the Northern Ohio area and the need, if any, for reactive
power reinforcements during summers 2004 and 2009. Certain requested
additional clarifications were provided to the FERC in October 2004.
FirstEnergy completed the implementation of recommendations relating to 2004 by
June 30, 2004, and is continuing to review results related to 2009. The
estimated capital expenditures required by 2009 are not expected to have a
material adverse effect on FirstEnergys financial results. FirstEnergy notes,
however, that 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. 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. SIPs 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. 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 are 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 90




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has accrued liabilities aggregating approximately $2.4 million as of September
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. On September 7, 2004, the EPA established new performance standards under
Clean Water Act Section 316(b) for reducing impacts on fish and shellfish from
cooling water intake structures at certain existing large electric generating
plants. The regulations call for reductions in impingement mortality, when
aquatic organisms are pinned against screens or other parts of a cooling water
intake system and entrainment, which occurs when aquatic species are drawn into
a facilitys cooling water system. CEI is conducting comprehensive
demonstration studies, due in 2008, to determine the operational measures,
equipment or restoration activities, if any, necessary for compliance by their
facilities with the performance standards. CEI is unable to predict the
outcome of such studies. Depending on the outcome of such studies, the future
cost of compliance with these standards may be substantial. Power Outages and Related Litigation On August 14, 2003, various states and parts of southern Canada
experienced widespread power outages. The outages affected approximately 1.4
million customers in FirstEnergys service area. On April 5, 2004, the U.S.
Canada Power System Outage Task Force released its final report on the
outages. In the final report, the Task Force concluded, among other things,
that the problems leading to the outages began in FirstEnergys Ohio service
area. Specifically, the final report concludes, among other things, that the
initiation of the August 14, 2003 power outages resulted from an alleged
failure of both FirstEnergy and ECAR to assess and understand perceived
inadequacies within the FirstEnergy system; inadequate situational awareness of
the developing conditions; and a perceived failure to adequately manage tree
growth in certain transmission rights of way. The Task Force also concluded
that there was a failure of the interconnected grids reliability organizations
(MISO and PJM) to provide effective diagnostic support. The final report is
publicly available through the Department of Energys website (www.doe.gov).
FirstEnergy believes that the final report does not provide a complete and
comprehensive picture of the conditions that contributed to the August 14, 2003
power outages and that it does not adequately address the underlying causes of
the outages. FirstEnergy remains convinced that the outages cannot be explained
by events on any one utilitys system. The final report contains 46
recommendations to prevent or minimize the scope of future blackouts.
Forty-five of those recommendations relate to broad industry or policy matters
while one, including subparts, relates to activities the Task Force recommends
be undertaken by FirstEnergy, MISO, PJM, and ECAR. FirstEnergy implemented
several initiatives, both prior to and since the August 14, 2003 power outages,
which are consistent with these and other recommendations and collectively
enhance the reliability of its electric system. FirstEnergy certified to NERC
on June 30, 2004, completion of various reliability recommendations and further
received independent verification of completion status from a NERC verification
team on July 14, 2004 (see 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 September 30, 2004 for any expenditures in excess of
those actually incurred through that date. Three substantially similar actions were filed in various Ohio state
courts by plaintiffs seeking to represent customers who allegedly suffered
damages as a result of the August 14, 2003 power outages. All three cases were
dismissed for lack of jurisdiction. One case was refiled at the PUCO and the
other two have been appealed. In addition to the one case that was refiled at
the PUCO, the Ohio Companies were named as respondents in a regulatory
proceeding that was initiated at the PUCO in response to complaints alleging
failure to provide reasonable and adequate service stemming primarily from the
August 14, 2003 power outages. One complaint has been filed against FirstEnergy in the New York State
Supreme Court. In this case, several plaintiffs in the New York City
metropolitan area allege that they suffered damages as a result of the August
14, 2003 power outages. None of the plaintiffs are customers of any
FirstEnergy affiliate. FirstEnergy filed a motion to dismiss with the Court on
October 22, 2004. No damage estimate has been provided and thus potential
liability has not been determined. FirstEnergy is vigorously defending these actions, but cannot predict the
outcome of any of these proceedings or whether any further regulatory
proceedings or legal actions may be instituted against the Companies. In
particular, if FirstEnergy or its subsidiaries were ultimately determined to
have legal liability in connection with these proceedings, it could have a
material adverse effect on FirstEnergys or its subsidiaries financial
condition and results of operations. 91




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Legal Matters Various lawsuits, claims (including claims for asbestos exposure) and
proceedings related to CEIs normal business operations are pending against CEI
and its subsidiaries. The most significant not otherwise discussed above are
described below. FENOC received a subpoena in late 2003 from a grand jury sitting in the
United States District Court for the Northern District of Ohio, Eastern
Division requesting the production of certain documents and records relating to
the inspection and maintenance of the reactor vessel head at the Davis-Besse
plant. FirstEnergy is unable to predict the outcome of this investigation. In
addition, FENOC remains subject to possible civil enforcement action by the NRC
in connection with the events leading to the Davis-Besse outage in 2002.
Further, a petition was filed with the NRC on March 29, 2004 by a group
objecting to the NRCs restart order of the Davis-Besse Nuclear Power Station.
The Petition seeks, among other things, suspension of the Davis-Besse operating
license. A June 2, 2004 ASLB denial of the petition was appealed to the NRC.
FENOC and the NRC staff filed opposition briefs on June 24, 2004. If it were
ultimately determined that FirstEnergy or its subsidiaries has legal liability
or is otherwise made subject to enforcement action based on the Davis-Besse
outage, it could have a material adverse effect on FirstEnergys or its
subsidiaries financial condition and results of operations. On August 12, 2004, the NRC publicly disclosed that it was notifying
FirstEnergy that it will increase its regulatory oversight of the Perry Nuclear
Power Plant as a result of problems with safety system equipment over the past
two years. CEI has a 44.85% interest in the Perry Nuclear Power Plant. The NRC
noted that the plant continues to operate safely. The increased oversight will
include an extensive NRC team inspection to access the equipment problems and
FirstEnergys corrective actions. The outcome of this increased oversight is
not known at this time. On October 20, 2004, FirstEnergy was notified by the SEC that the
previously disclosed informal inquiry initiated by the SECs Division of
Enforcement in September 2003 relating to the restatements in August 2003 of
previously reported results by FirstEnergy and CEI and the Davis-Besse extended
outage has become the subject of a formal order of investigation. The SECs
formal order of investigation also encompasses issues raised during the SECs
examination of FirstEnergy and the Companies under the PUHCA. Concurrent with
this notification, FirstEnergy received a subpoena asking for background
documents and documents related to the restatements and Davis-Besse issues.
FirstEnergy has cooperated fully with the informal inquiry and will continue to
do so with the formal investigation. On September 16, 2004, the FERC issued an order that imposed additional
obligations on CEI under certain pre-Open Access transmission contracts among
CEI and the cities of Cleveland and Painesville. Under the FERCs decision,
CEI may be responsible for a portion of new energy market charges imposed by
the MISO when its energy markets begin in the spring of 2005. CEI filed for
rehearing of the order from the FERC on October 18, 2004. The impact of the
FERC decision on CEI is dependent upon many factors, including the arrangements
made by the cities for transmission service, the startup date for the MISO
energy market, and the resolution of the rehearing request, and cannot be
determined at this time. If it were ultimately determined that FirstEnergy or its subsidiaries has
legal liability or is otherwise made subject to liability based on any of the
above matters, it could have a material adverse effect on FirstEnergys or its
subsidiaries financial condition and results of operations. 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 92




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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, weather-related impacts and
electricity provided by alternative suppliers. Pension and Other Postretirement Benefits Accounting FirstEnergys pension and postretirement 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. 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 in the first
nine months 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. In the third quarter of 2004, FirstEnergy made a $500 million voluntary
contribution ($32 million funded by CEI) to its pension plan. This contribution
will mitigate future funding requirements and significantly reduce the year-end
minimum pension liability that currently reduces CEIs accumulated other
comprehensive income by $25 million. 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 93




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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 2004, 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 September 30, 2004, CEI had $1.7 billion of
goodwill. New Accounting Standards And Interpretations  EITF Issue No. 03-1, The Meaning of Other-Than-Temporary and Its
Application to Certain Investments In March 2004, the EITF reached a consensus on the application guidance
for Issue 03-1. EITF 03-1 provides a model for determining when investments in
certain debt and equity securities are considered other than temporarily
impaired. When an impairment is other-than-temporary, the investment must be
measured at fair value and the impairment loss recognized in earnings. The
recognition and measurement provisions of EITF 03-1, which were to be effective
for periods beginning after June 15, 2004, were delayed by the issuance of FSP
EITF 03-1-1 in September 2004. During the period of delay, CEI will continue to
evaluate its investments as required by existing authoritative guidance.  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 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, 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. 94




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THE TOLEDO EDISON COMPANY 
 CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (Unaudited)
 Three Months Ended
    
    Nine Months EndedSeptember 30,
    
    September 30,2004
    
    2003
    
    2004
    
    2003Restated
    
    
    
    
    
    Restated(See Note 2)
    
    
    
    
    
    (See Note 2)(In thousands)STATEMENTS OF INCOMEOPERATING REVENUES
    
    $
    276,342
    
    
    $
    260,197
    
    
    $
    755,106
    
    
    $
    708,007OPERATING EXPENSES AND TAXES:Fuel
    
    
    13,908
    
    
    
    2,940
    
    
    
    37,195
    
    
    
    17,494Purchased power
    
    
    79,774
    
    
    
    81,795
    
    
    
    236,869
    
    
    
    230,271Nuclear operating costs
    
    
    43,827
    
    
    
    64,681
    
    
    
    122,685
    
    
    
    195,877Other operating costs
    
    
    43,865
    
    
    
    38,560
    
    
    
    121,228
    
    
    
    104,798Provision for depreciation and amortization
    
    
    43,183
    
    
    
    36,142
    
    
    
    115,422
    
    
    
    106,460General taxes
    
    
    14,924
    
    
    
    14,305
    
    
    
    41,252
    
    
    
    43,279Income taxes (benefit)
    
    
    11,963
    
    
    
    3,024
    
    
    
    18,465
    
    
    
    (12,366
    )Total operating expenses and taxes
    
    
    251,444
    
    
    
    241,447
    
    
    
    693,116
    
    
    
    685,813OPERATING INCOME
    
    
    24,898
    
    
    
    18,750
    
    
    
    61,990
    
    
    
    22,194OTHER INCOME
    
    
    4,172
    
    
    
    5,724
    
    
    
    14,724
    
    
    
    12,600NET INTEREST CHARGES:Interest on long-term debt
    
    
    4,015
    
    
    
    8,691
    
    
    
    23,057
    
    
    
    30,862Allowance for borrowed funds used during construction
    
    
    (741
    )
    
    
    (1,458
    )
    
    
    (2,843
    )
    
    
    (3,948
    )Other interest expense
    
    
    1,350
    
    
    
    639
    
    
    
    2,945
    
    
    
    1,068Net interest charges
    
    
    4,624
    
    
    
    7,872
    
    
    
    23,159
    
    
    
    27,982INCOME BEFORE CUMULATIVE EFFECT OF
ACCOUNTING CHANGE
    
    
    24,446
    
    
    
    16,602
    
    
    
    53,555
    
    
    
    6,812Cumulative effect of accounting change (net of income taxes
of $18,201,000) (Note 2)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    25,550NET INCOME
    
    
    24,446
    
    
    
    16,602
    
    
    
    53,555
    
    
    
    32,362PREFERRED STOCK DIVIDEND REQUIREMENTS
    
    
    2,211
    
    
    
    2,211
    
    
    
    6,633
    
    
    
    6,627EARNINGS ON COMMON STOCK
    
    $
    22,235
    
    
    $
    14,391
    
    
    $
    46,922
    
    
    $
    25,735STATEMENTS OF COMPREHENSIVE INCOMENET INCOME
    
    $
    24,446
    
    
    $
    16,602
    
    
    $
    53,555
    
    
    $
    32,362OTHER COMPREHENSIVE INCOME (LOSS):Minimum liability for unfunded retirement benefits
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    9,622Unrealized gain (loss) on available for sale securities
    
    
    913
    
    
    
    1,903
    
    
    
    (379
    )
    
    
    16,384Other comprehensive income (loss)
    
    
    913
    
    
    
    1,903
    
    
    
    (379
    )
    
    
    26,006Income tax related to other comprehensive income
    
    
    (375
    )
    
    
    (792
    )
    
    
    155
    
    
    
    (10,447
    )Other comprehensive income (loss), net of tax
    
    
    538
    
    
    
    1,111
    
    
    
    (224
    )
    
    
    15,559TOTAL COMPREHENSIVE INCOME
    
    $
    24,984
    
    
    $
    17,713
    
    
    $
    53,331
    
    
    $
    47,921
 The preceding Notes to Consolidated Financial Statements as they relate to The
Toledo Edison Company are an integral part of these statements. 95




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THE TOLEDO EDISON COMPANY 
 CONSOLIDATED BALANCE SHEETS (Unaudited)
 September 30,
    
    December 31,2004
    
    2003(In thousands)ASSETSUTILITY PLANT:In service
    
    $
    1,826,476
    
    
    $
    1,714,870Less-Accumulated provision for depreciation
    
    
    764,337
    
    
    
    721,7541,062,139
    
    
    
    993,116Construction work in progress-Electric plant
    
    
    72,808
    
    
    
    125,051Nuclear fuel
    
    
    4,275
    
    
    
    20,18977,083
    
    
    
    145,2401,139,222
    
    
    
    1,138,356OTHER PROPERTY AND INVESTMENTS:Investment in lessor notes
    
    
    190,658
    
    
    
    200,938Nuclear plant decommissioning trusts
    
    
    269,492
    
    
    
    240,634Long-term notes receivable from associated companies
    
    
    163,592
    
    
    
    163,626Other
    
    
    2,098
    
    
    
    2,119625,840
    
    
    
    607,317CURRENT ASSETS:Cash and cash equivalents
    
    
    15
    
    
    
    2,237Receivables-Customers
    
    
    6,439
    
    
    
    4,083Associated companies
    
    
    12,202
    
    
    
    29,158Other
    
    
    2,307
    
    
    
    14,386Notes receivable from associated companies
    
    
    40,396
    
    
    
    19,316Materials and supplies, at average cost
    
    
    39,523
    
    
    
    35,147Prepayments and other
    
    
    733
    
    
    
    6,704101,615
    
    
    
    111,031DEFERRED CHARGES:Regulatory assets
    
    
    387,438
    
    
    
    459,040Goodwill
    
    
    504,522
    
    
    
    504,522Property taxes
    
    
    24,443
    
    
    
    24,443Other
    
    
    23,803
    
    
    
    10,689940,206
    
    
    
    998,694$
    2,806,883
    
    
    $
    2,855,398CAPITALIZATION AND LIABILITIESCAPITALIZATION:Common stockholders equity-Common stock, $5 par value, authorized 60,000,000 shares-
39,133,887 shares outstanding
    
    $
    195,670
    
    
    $
    195,670Other paid-in capital
    
    
    428,559
    
    
    
    428,559Accumulated other comprehensive income
    
    
    11,448
    
    
    
    11,672Retained earnings
    
    
    160,542
    
    
    
    113,620Total common stockholders equity
    
    
    796,219
    
    
    
    749,521Preferred stock not subject to mandatory redemption
    
    
    126,000
    
    
    
    126,000Long-term debt
    
    
    303,854
    
    
    
    270,0721,226,073
    
    
    
    1,145,593CURRENT LIABILITIES:Currently payable long-term debt
    
    
    90,950
    
    
    
    283,650Short-term borrowings
    
    
    
    
    
    
    70,000Accounts payable-Associated companies
    
    
    123,062
    
    
    
    132,876Other
    
    
    3,062
    
    
    
    2,816Notes payable to associated companies
    
    
    385,263
    
    
    
    285,953Accrued taxes
    
    
    55,831
    
    
    
    55,604Accrued interest
    
    
    4,872
    
    
    
    12,412Lease market valuation liability
    
    
    24,600
    
    
    
    24,600Other
    
    
    96,232
    
    
    
    37,299783,872
    
    
    
    905,210NONCURRENT LIABILITIES:Accumulated deferred income taxes
    
    
    198,038
    
    
    
    201,954Accumulated deferred investment tax credits
    
    
    25,619
    
    
    
    27,200Retirement benefits
    
    
    39,167
    
    
    
    47,006Asset retirement obligation
    
    
    191,118
    
    
    
    181,839Lease market valuation liability
    
    
    274,150
    
    
    
    292,600Other
    
    
    68,846
    
    
    
    53,996796,938
    
    
    
    804,595COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 3)$
    2,806,883
    
    
    $
    2,855,398
 The preceding Notes to Consolidated Financial Statements as they relate to The
Toledo Edison Company are an integral part of these balance sheets. 96




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THE TOLEDO EDISON COMPANY 
 CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
 Three Months Ended
    
    Nine Months EndedSeptember 30,
    
    September 30,2004
    
    2003
    
    2004
    
    2003Restated
    
    
    
    
    
    Restated(See Note 2)
    
    
    
    
    
    (See Note 2)(In thousands)CASH FLOWS FROM OPERATING ACTIVITIES:Net income
    
    $
    24,446
    
    
    $
    16,602
    
    
    $
    53,555
    
    
    $
    32,362Adjustments to reconcile net income to net
cash from operating activities-Provision for depreciation and amortization
    
    
    43,183
    
    
    
    36,142
    
    
    
    115,422
    
    
    
    106,460Nuclear fuel and capital lease amortization
    
    
    7,058
    
    
    
    2,182
    
    
    
    17,596
    
    
    
    6,770Deferred operating lease costs, net
    
    
    9,689
    
    
    
    (4,212
    )
    
    
    (26,585
    )
    
    
    (39,671
    )Deferred income taxes, net
    
    
    (4,092
    )
    
    
    (11,570
    )
    
    
    (7,709
    )
    
    
    5,421Amortization of investment tax credits
    
    
    (516
    )
    
    
    (514
    )
    
    
    (1,581
    )
    
    
    (1,542
    )Accrued retirement benefit obligation
    
    
    1,324
    
    
    
    7,800
    
    
    
    4,733
    
    
    
    5,467Accrued compensation, net
    
    
    516
    
    
    
    (65
    )
    
    
    1,477
    
    
    
    (2,754
    )Cumulative effect of accounting change (Note 2)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (43,751
    )Pension trust contribution
    
    
    (12,572
    )
    
    
    
    
    
    
    (12,572
    )
    
    
    Receivables
    
    
    69,908
    
    
    
    25,437
    
    
    
    95,383
    
    
    
    8,058Materials and supplies
    
    
    (725
    )
    
    
    (1,317
    )
    
    
    (4,376
    )
    
    
    3,833Prepayments and other current assets
    
    
    677
    
    
    
    3,263
    
    
    
    5,971
    
    
    
    (5,716
    )Accounts payable
    
    
    6,202
    
    
    
    (54,140
    )
    
    
    (9,568
    )
    
    
    (65,990
    )Accrued taxes
    
    
    (3,508
    )
    
    
    16,393
    
    
    
    227
    
    
    
    17,794Accrued interest
    
    
    (7,169
    )
    
    
    (3,862
    )
    
    
    (7,540
    )
    
    
    (3,988
    )Other
    
    
    (14,759
    )
    
    
    (11,236
    )
    
    
    (9,679
    )
    
    
    (29,727
    )Net cash provided from (used for) operating activities
    
    
    119,662
    
    
    
    20,903
    
    
    
    214,754
    
    
    
    (6,974
    )CASH FLOWS FROM FINANCING ACTIVITIES:New Financing-Long-term debt
    
    
    30,500
    
    
    
    
    
    
    
    103,500
    
    
    
    Short-term borrowings, net
    
    
    146,370
    
    
    
    122,451
    
    
    
    29,310
    
    
    
    254,041Redemptions and Repayments-Long-term debt
    
    
    (246,591
    )
    
    
    (34,981
    )
    
    
    (261,591
    )
    
    
    (117,743
    )Dividend Payments-Preferred stock
    
    
    (2,211
    )
    
    
    (2,205
    )
    
    
    (6,633
    )
    
    
    (6,626
    )Net cash provided from (used for) financing activities
    
    
    (71,932
    )
    
    
    85,265
    
    
    
    (135,414
    )
    
    
    129,672CASH FLOWS FROM INVESTING ACTIVITIES:Property additions
    
    
    (16,950
    )
    
    
    (21,138
    )
    
    
    (36,377
    )
    
    
    (56,886
    )Loan repayments from (loans to) associated companies, net
    
    
    (20,389
    )
    
    
    138
    
    
    
    (21,046
    )
    
    
    (8,602
    )Investment in lessor notes
    
    
    
    
    
    
    3,399
    
    
    
    10,280
    
    
    
    20,989Contributions to nuclear decommissioning trust
    
    
    (7,135
    )
    
    
    (14,271
    )
    
    
    (21,406
    )
    
    
    (21,406
    )Debt remarketing investments
    
    
    
    
    
    
    (73,231
    )
    
    
    
    
    
    
    (73,231
    )Other
    
    
    (3,256
    )
    
    
    (98
    )
    
    
    (13,013
    )
    
    
    7,025Net cash used for investing activities
    
    
    (47,730
    )
    
    
    (105,201
    )
    
    
    (81,562
    )
    
    
    (132,111
    )Net change in cash and cash equivalents
    
    
    
    
    
    
    967
    
    
    
    (2,222
    )
    
    
    (9,413
    )Cash and cash equivalents at beginning of period
    
    
    15
    
    
    
    10,308
    
    
    
    2,237
    
    
    
    20,688Cash and cash equivalents at end of period
    
    $
    15
    
    
    $
    11,275
    
    
    $
    15
    
    
    $
    11,275
 The preceding Notes to Consolidated Financial Statements as they relate to The
Toledo Edison Company are an integral part of these statements. 97




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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 September 30, 2004, and the related
consolidated statements of income, comprehensive income and cash flows for each
of the three-month and nine-month periods ended September 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 nine-month periods ended September 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
November 2, 2004 98




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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 TE 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 third quarter and first nine 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 $1.1 million ($0.6 million
after tax) and $2.1 million ($1.2 million after tax) in the third quarter and
the first nine months of 2003, respectively. In addition, TEs interest expense
was overstated by $0.3 million ($0.2 million after tax) and $1.6 million ($1.0
million after tax) in the third quarter and the first nine months of 2003,
respectively. 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 third quarter of 2004 increased to $22
million from $14 million in the third quarter of 2003. For the first nine
months of 2004, earnings on common stock increased to $47 million from $26
million in the same period of 2003. Earnings on common stock in the first nine
months of 2003 included an after-tax credit of $26 million from the cumulative
effect of an accounting change due to the adoption of SFAS 143. Income before
the cumulative effect was $7 million in the first nine months of 2003.
Increased earnings in both 2004 periods resulted principally from higher
operating revenues, lower nuclear operating costs and reduced interest charges
 partially offset by higher fuel and other operating costs and provisions for
depreciation and amortization. Revenues in both periods were higher due to
significant increases in sales to FES. Lower nuclear operating costs in the
third quarter and the first nine months of 2004, compared with the same periods
of 2003, were due to reduced incremental maintenance costs associated with the
Davis-Besse extended outage and the absence of nuclear refueling outages at
Beaver Valley Unit 2 and the Perry Plant in 2003. Lower net interest charges in
the third quarter and the first nine months of 2004, compared with the same
periods of 2003, were primarily due to debt redemptions and refinancing
activities. Operating revenues increased by $16 million or 6.2% in the third quarter
from the same period of 2003. Higher revenues resulted principally from a $25
million (38.9%) increase in wholesale sales (primarily to FES) due to
increased nuclear generation available for sale with almost no change in total
generation sales revenues from franchise customers. Reduced retail generation
revenues (residential and commercial  $1 million each) in the third quarter of
2004 reflected increases in electric generation services to residential and
commercial customers provided by alternative suppliers as a percent of total
sales deliveries in TEs franchise area of 5.6 percentage points and 1.7
percentage points, respectively, while shopping by industrial customers was
unchanged. Increased industrial customer generation revenues of $3 million was
due to higher unit prices offsetting a 2.3% decrease in kilowatt-hour sales. In
the first nine months of 2004, operating revenues increased by $47 million or
6.7% primarily as a result of a $73 million increase in wholesale revenues
(primarily to FES) due to increased available nuclear generation. The increase
in wholesale revenues was partially offset by a 4.6% decrease in retail
generation sales, which resulted in lower revenues of $8 million. Decreased
retail generation revenues in the first nine months of 2004 reflected the same
trend in shopping for generation providers (increases of 5.8 and 2.1 percentage
points for residential and commercial customers, respectively, and a slight
decrease of 0.4 percentage points for industrial customers). Retail revenues
decreased due to lower kilowatt-hour sales in all customer sectors and lower
unit prices in the residential and commercial sectors. Industrial revenues
remained unchanged as lower kilowatt-hour sales were offset by higher unit
prices. Revenues from distribution throughput decreased by $7 million and $13
million in the third quarter and first nine months of 2004, respectively, as
compared to the same periods of 2003, reflecting reduced usage and lower unit
prices in all customer sectors. Distribution deliveries to commercial and
industrial customers decreased and deliveries to residential customers were
nearly unchanged in the third quarter of 2004 as compared to the same quarter
of 2003. Total distribution deliveries decreased by 2.4% in the first nine
months of 2004, compared to the same period in 2003. Weak economic conditions
in TEs franchise area contributed to lower distribution deliveries to
commercial and industrial customers in the third quarter and first nine months
of 2004. Lower unit prices in all customer sectors for both periods contributed
to the decrease in revenues from electricity throughput. 99




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Under the Ohio transition plan, TE provides incentives to customers to
encourage switching to alternative energy providers  $2 million of additional
credits in the third quarter and $3 million of additional credits in the first
nine months of 2004 compared with the corresponding periods of 2003. These
revenue reductions are deferred for future recovery under TEs transition plan
and do not materially affect current period earnings. Changes in electric generation sales and distribution deliveries in the
third quarter and first nine months of 2004 from the corresponding periods of
2003 are summarized in the following table: Changes in KWH Sales
    
    Three Months
    
    Nine MonthsIncrease (Decrease)Electric Generation:Retail
    
    
    (4.5
    )%
    
    
    (4.6
    )%Wholesale
    
    
    69.7
    %
    
    
    61.7
    %Total Electric Generation Sales
    
    
    27.6
    %
    
    
    22.7
    %Distribution Deliveries:Residential
    
    
    (0.4
    )%
    
    
    (3.4
    )%Commercial
    
    
    (1.9
    )%
    
    
    (1.2
    )%Industrial
    
    
    (2.5
    )%
    
    
    (2.3
    )%Total Distribution Deliveries
    
    
    (2.0
    )%
    
    
    (2.4
    )%
 Operating Expenses and Taxes Total operating expenses and taxes increased by $10 million in the third
quarter and $7 million in the first nine 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
    
    Nine Months(In millions)Increase (Decrease)Fuel
    
    $
    11
    
    
    $
    20Purchased power costs
    
    
    (2
    )
    
    
    7Nuclear operating costs
    
    
    (21
    )
    
    
    (73
    )Other operating costs
    
    
    5
    
    
    
    16Total operation and maintenance expenses
    
    
    (7
    )
    
    
    (30
    )Provision for depreciation and amortization
    
    
    7
    
    
    
    9General taxes
    
    
    1
    
    
    
    (3
    )Income taxes
    
    
    9
    
    
    
    31Total operating expenses and taxes
    
    $
    10
    
    
    $
    7
 Higher fuel costs in the third quarter and first nine months of 2004,
compared with the same periods of 2003, resulted principally from increased
nuclear generation. Purchased power costs increased in the first nine months of
2004, compared to the same period of 2003, due to higher unit costs, partially
offset by lower kilowatt-hours purchased. The decreases in nuclear operating
costs for both periods were due to reduced incremental costs associated with
the Davis-Besse extended outage and work performed during the Perry plant
56-day refueling outage (19.91% interest) in the second quarter of 2003 and the
Beaver Valley Unit 2 refueling outage (19.91% interest) in the third quarter of
2003. Other operating costs increased in the third quarter and first nine
months of 2004, compared to the same periods of 2003, in part from higher
vegetation management costs. The increase in depreciation and amortization charges in the third
quarter of 2004, compared with the third quarter of 2003, was primarily due to
higher amortization of regulatory assets ($10 million), partially offset by
higher shopping incentive deferrals ($2 million) and deferred interest on the
shopping incentives (see Regulatory Matters) ($1 million). The increase in
depreciation and amortization charges in the first nine months of 2004,
compared with the first nine months of 2003, was primarily due to the increased
amortization of regulatory assets ($14 million), partially offset by higher
shopping incentive deferrals ($3 million) and deferred interest on the
shopping incentives ($4 million). Other Income Other income increased by $2 million in the first nine months of 2004,
compared to the same period of 2003, due in part to the absence of costs
related to closing the Acme power plant in 2003. Net Interest Charges Net interest charges continued to trend lower, decreasing by $3 million in
the third quarter of 2004 and $5 million in the first nine months of 2004 from
the same periods of 2003, reflecting redemptions and refinancings since the end
of the 100




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third quarter of 2003. TEs long-term debt redemptions of $230 million and the
repricing of $54 million of pollution control notes during the first nine
months of 2004 are expected to result in annualized savings of approximately
$19 million. 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 September 30, 2004, TE had approximately $15,000 of cash and cash
equivalents, compared with $2 million as of December 31, 2003. The major
sources of changes in these balances are summarized below. Cash Flows From Operating Activities Cash provided from (used for) operating activities during the third
quarter and first nine months of 2004, compared with the corresponding periods
in 2003, were as follows: Three Months Ended
    
    Nine Months EndedSeptember 30,
    
    September 30,Operating Cash Flows
    
    2004
    
    2003
    
    2004
    
    2003(In millions)Cash earnings (1)
    
    $
    82
    
    
    $
    46
    
    
    $
    157
    
    
    $
    69Pension trust contribution
    
    
    (13
    )
    
    
    
    
    
    
    (13
    )
    
    
    Working capital and other
    
    
    51
    
    
    
    (25
    )
    
    
    71
    
    
    
    (76
    )Total
    
    $
    120
    
    
    $
    21
    
    
    $
    215
    
    
    $
    (7
    )
  (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 $99 million in the
third quarter of 2004 from the third quarter of 2003 as a result of a $36
million increase in cash earnings as described above under Results of
Operations and a $76 million increase from changes in working capital. These
increases were partially offset by a $13 million voluntary pension trust
contribution. The largest factor contributing to the change in working capital
was an increase in accounts payable. Net cash provided from operating
activities increased $222 million in the first nine months of 2004 compared to
the same period last year as a result of an $88 million increase in cash
earnings and a $147 million increase from changes in working capital, partially
offset by the $13 million pension contribution. The change in working capital
reflects changes in receivables and payables. The increase from the change in
working capital also included the receipt of $12 million in proceeds from the
settlement of TEs claim against NRG, Inc. for the terminated sale of its Bay
Shore Plant. Cash Flows From Financing Activities Net cash used for financing activities increased by $157 million and $265
million in the third quarter and the first nine months of 2004 from the same
periods of 2003, respectively, and resulted from an increase in net debt
redemptions in both periods. As of September 30, 2004, TE had $40 million of cash and temporary
investments (which include short-term notes receivable from associated
companies) and $385 million of short-term indebtedness. TE has obtained
authorization from the PUCO to incur short-term debt of up to $500 million
(including the utility money pool described below). TE had the capability to
issue $712 million of additional FMB on the basis of property additions and
retired bonds under the terms of its mortgage indenture. Based upon applicable
earnings coverage tests, TE could issue up to $370 million of preferred stock
(assuming no additional debt was issued) as of September 30, 2004. 101




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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
third quarter of 2004 was 1.28%. On September 2, 2004, $30.5 million Ohio Water Development Authority
pollution control notes were refunded. The new notes were issued in a Dutch
Auction interest rate mode, insured by a municipal bond insurance policy and
secured by FMBs. On October 1, 2004, Ohio Water Development Authority and Ohio
Air Quality Development Authority Series 2000-A pollution control notes
aggregating $33.2 million and $34.1 million, respectively, were each remarketed
in a Dutch Auction interest rate mode. Each series of notes is insured by a
separate municipal bond insurance policy and remains secured by separate FMBs. TE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 August 26, 2004, S&P stated that a favorable outcome of the Ohio Rate
Stabilization Plan auction process and a favorable resolution of pending
environmental litigation would support a higher ratings outlook, or possibly a
higher rating. S&P noted that a ratings upgrade in 2004 does not appear likely
because those major issues would most likely not be resolved before the end of
2004. On September 14, 2004, S&P stated that FirstEnergys $500 million
voluntary contribution to its pension plan was credit neutral. Cash Flows From Investing Activities Net cash used for investing activities decreased by $57 million and $51
million in the third quarter and the first nine months of 2004, respectively,
from the same periods of 2003. The decreases in both periods were primarily
due to the absence of debt remarketing investments of $73 million in the third
quarter of 2003 partially offset by increased loans to associated companies of
$20 million and $12 million in the third quarter and the first nine months of
2004, respectively. During the fourth quarter of 2004, capital requirements for property
additions are expected to be about $30 million, including $15 million for
nuclear fuel. Those 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 September 30, 2004, the present value of these
sale and leaseback operating lease commitments, net of trust investments, total
$572 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 $68 million of
off-balance sheet financing as of September 30, 2004. Equity Price Risk Included in TEs nuclear decommissioning trust investments are marketable
equity securities carried at their market value of approximately $167 million
and $145 million as of September 30, 2004 and December 31, 2003, respectively.
A hypothetical 10% decrease in prices quoted by stock exchanges would result in
a $17 million reduction in fair value as of September 30, 2004. 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.
TE 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 TEs customers elects to obtain power
from an 102




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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 Companies filed an application with the PUCO
to establish generation service rates beginning January 1, 2006, in response to
expressed concerns by the PUCO about price and supply uncertainty following the
end of the market development period. The filing included two options:  
    
    A competitive auction, which would establish a price for
generation that customers would be charged during the period
covered by the auction, or  
    
    A Rate Stabilization Plan, which would extend current
generation prices through 2008, ensuring adequate generation
supply at stable prices, and continuing TEs support of energy
efficiency and economic development efforts. Under that proposal, TE requested:  
    
    Extension of the transition cost amortization period TE
from mid-2007 to 2008;  
    
    Deferral of interest costs on the accumulated shopping
incentives and other cost deferrals as new regulatory assets;
and  
    
    Ability to initiate a request to increase generation
rates under certain limited conditions. On February 23, 2004, after consideration of the PUCO Staff comments and
testimony as well as those provided by some of the intervening parties, 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:  
    
    Limiting TEs ability to request adjustments in
generation charges during 2006 through 2008 for increases in
taxes;  
    
    Expanding the availability of market support generation;  
    
    Revising the kilowatt-hour target level and the time period for recovering regulatory transition charges;  
    
    Establishing a 3-year competitive bid process for generation;  
    
    Establishing the 2005 generation credit for shopping
customers, which would be extended as a cap through 2008; and  
    
    Denying the ability to defer costs for future recovery
of distribution reliability improvement expenditures. On June 18, 2004, 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:  
    
    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; 103




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
    
    Approving the revised kilowatt-hour target level and
time period for recovery of regulatory transition costs as
presented by TE in its rehearing application;  
    
    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;  
    
    Revising the calculation of the shopping credit cap for
certain commercial and small industrial rate schedules; and  
    
    Relaxing the notice requirement for availability of
enhanced shopping credits in a number of instances. On August 5, 2004, 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. On October
1, 2004, the OCC filed an appeal with the Ohio Supreme Court to overturn the
June 9, 2004 PUCO order. TE filed a proposed competitive bid process which the PUCO modified on
October 6, 2004. The PUCO approved the rules for the competitive bid process
setting a three-year supply period (2006-2008) requirement for generation
service suppliers and a load cap for individual suppliers. In mid-October, the
initial auction schedule was revised so that Part 1 and Part 2 auction bidder
applications are due November 4 and November 15, 2004, respectively; the trial
auction is scheduled to occur on December 3; the auction would commence
December 8 and the PUCO will accept or reject the auction results within two
business days after the completion of the auction. FirstEnergy has elected to
not participate in the auction. 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 September 30, 2004 and December 31, 2003 were $387 million and
$459 million, respectively. 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 a review of various reliability practices.
The Company response confirmed that its review was completed and that various
enhancements were underway to current practices. On February 10, 2004, NERC
issued its Recommended Actions to Prevent and Mitigate the Impacts of Future
Cascading Blackouts, a portion of which were directed at the FirstEnergy
companies and broadly focused on initiatives that were recommended for
completion by June 30, 2004. FirstEnergys detailed implementation plan was
endorsed by the NERC Board of Trustees on May 7, 2004. The various initiatives
recommended by NERC were certified as complete by June 30, 2004, with one minor
exception related to reactive testing of certain generators expected to be
completed later in 2004. On February 26 and 27, 2004, TE, as part of a NERC review of control area
operations throughout the United States, participated in a NERC Control Area
Readiness Audit. The final audit report, completed on May 6, 2004, identified
positive observations and included various recommendations for reliability
improvement. FirstEnergy reported completion of those recommendations on June
30, 2004, with one exception related to MISOs implementation of a voltage
stability tool expected to be completed later this year. On April 5, 2004, the U.S.  Canada Power System Outage Task Force issued
a Final Report on the August 14, 2003 power outages. The Final Report contains
46 recommendations to prevent or minimize the scope of future blackouts.
Forty-five of those recommendations relate to broad industry or policy matters
while one relates to activities the Task Force recommended be undertaken by
FirstEnergy, MISO, PJM and ECAR. FirstEnergy completed the Task Force
recommendations that were directed toward FirstEnergy and reported completion
of those activities on June 30, 2004. With respect to each of the foregoing initiatives, FirstEnergy requested
and NERC provided, a technical assistance team of experts to provide ongoing
guidance and assistance in implementing and confirming timely and successful
completion. NERC further assembled an independent verification team to confirm
implementation of the foregoing initiatives required to be completed as of June
30, 2004. The NERC Verification Team reported, on July 14, 2004, that
FirstEnergy has completed the recommended policies, procedures and actions
required to be completed by 104




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June 30, 2004 or summer 2004, with exceptions noted by FirstEnergy.
Implementation of the recommendations has not required incremental material
investment or upgrades to existing equipment. On March 1, 2004, TE filed, in accordance with a November 25, 2003 order
from the PUCO, their plan for addressing certain issues identified by the PUCO
from the U.S.  Canada Power System Outage Task Force interim report. In
particular, the filing addressed upgrades to FirstEnergys control room
computer hardware and software and enhancements to the training of control room
operators. The PUCO will review the plan before determining the next steps, if
any, in the proceeding. On April 22, 2004, FirstEnergy filed with the FERC the results of the
FERC-ordered independent study of part of Ohios power grid. The study
examined, among other things, the reliability of the transmission grid in
critical points in the Northern Ohio area and the need, if any, for reactive
power reinforcements during summers 2004 and 2009. Certain requested
additional clarifications were provided to the FERC in October 2004.
FirstEnergy completed the implementation of recommendations relating to 2004 by
June 30, 2004, and is continuing to review results related to 2009. The
estimated capital expenditures required by 2009 are not expected to have a
material adverse effect on FirstEnergys financial results. FirstEnergy notes,
however, that 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. 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. SIPs 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 required 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. 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 are 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 September 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. On September 7, 2004, the EPA established new performance standards under
Clean Water Act Section 316(b) for reducing impacts on fish and shellfish from
cooling water intake structures at certain existing large electric generating
plants. The regulations call for reductions in impingement mortality, when
aquatic organisms are pinned against screens or other parts of a cooling water
intake system and entrainment, which occurs when aquatic species are 105




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drawn into a facilitys cooling water system. TE is conducting comprehensive
demonstration studies, due in 2008, to determine the operational measures,
equipment or restoration activities, if any, necessary for compliance by their
facilities with the performance standards. TE is unable to predict the outcome
of such studies. Depending on the outcome of such studies, the future cost of
compliance with these standards may be substantial. Power Outages and Related Litigation On August 14, 2003, various states and parts of southern Canada
experienced widespread power outages. The outages affected approximately 1.4
million customers in FirstEnergys service area. On April 5, 2004, the U.S.
Canada Power System Outage Task Force released its final report on the
outages. In the final report, the Task Force concluded, among other things,
that the problems leading to the outages began in FirstEnergys Ohio service
area. Specifically, the final report concludes, among other things, that the
initiation of the August 14, 2003 power outages resulted from an alleged
failure of both FirstEnergy and ECAR to assess and understand perceived
inadequacies within the FirstEnergy system; inadequate situational awareness of
the developing conditions; and a perceived failure to adequately manage tree
growth in certain transmission rights of way. The Task Force also concluded
that there was a failure of the interconnected grids reliability organizations
(MISO and PJM) to provide effective diagnostic support. The final report is
publicly available through the Department of Energys website (www.doe.gov).
FirstEnergy believes that the final report does not provide a complete and
comprehensive picture of the conditions that contributed to the August 14, 2003
power outages and that it does not adequately address the underlying causes of
the outages. FirstEnergy remains convinced that the outages cannot be explained
by events on any one utilitys system. The final report contains 46
recommendations to prevent or minimize the scope of future blackouts.
Forty-five of those recommendations relate to broad industry or policy matters
while one, including subparts, relates to activities the Task Force recommends
be undertaken by FirstEnergy, MISO, PJM, and ECAR. FirstEnergy implemented
several initiatives, both prior to and since the August 14, 2003 power outages,
which are consistent with these and other recommendations and collectively
enhance the reliability of its electric system. FirstEnergy certified to NERC
on June 30, 2004, completion of various reliability recommendations and further
received independent verification of completion status from a NERC verification
team on July 14, 2004 (see 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 September 30, 2004 for any expenditures in excess of
those actually incurred through that date. Three substantially similar actions were filed in various Ohio state
courts by plaintiffs seeking to represent customers who allegedly suffered
damages as a result of the August 14, 2003 power outages. All three cases were
dismissed for lack of jurisdiction. One case was refiled at the PUCO and the
other two have been appealed. In addition to the one case that was refiled at
the PUCO, the Ohio Companies were named as respondents in a regulatory
proceeding that was initiated at the PUCO in response to complaints alleging
failure to provide reasonable and adequate service stemming primarily from the
August 14, 2003 power outages. One complaint has been filed against FirstEnergy in the New York State
Supreme Court. In this case, several plaintiffs in the New York City
metropolitan area allege that they suffered damages as a result of the August
14, 2003 power outages. None of the plaintiffs are customers of any
FirstEnergy affiliate. FirstEnergy filed a motion to dismiss with the Court on
October 22, 2004. No damage estimate has been provided and thus potential
liability has not been determined. FirstEnergy is vigorously defending these actions, but cannot predict the
outcome of any of these proceedings or whether any further regulatory
proceedings or legal actions may be instituted against the Companies. In
particular, if FirstEnergy or its subsidiaries were ultimately determined to
have legal liability in connection with these proceedings, it could have a
material adverse effect on FirstEnergys or its subsidiaries financial
condition and results of operations. Legal Matters Various lawsuits, claims (including claims for asbestos exposure) and
proceedings related to TEs normal business operations are pending against TE
and its subsidiaries. The most significant not otherwise discussed above are
described below. 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 106




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March 29, 2004 by a group objecting to the NRCs restart order of the
Davis-Besse Nuclear Power Station. The Petition seeks, among other things,
suspension of the Davis-Besse operating license. A June 2, 2004 ASLB denial of
the petition was appealed to the NRC. FENOC and the NRC staff filed opposition
briefs on June 24, 2004. If it were ultimately determined that FirstEnergy or
its subsidiaries has legal liability or is otherwise made subject to
enforcement action based on the Davis-Besse outage, it could have a material
adverse effect on FirstEnergys or its subsidiaries financial condition and
results of operations. On August 12, 2004, the NRC publicly disclosed that it was notifying
FirstEnergy that it will increase its regulatory oversight of the Perry Nuclear
Power Plant as a result of problems with safety system equipment over the past
two years. TE has a 19.91% interest in the Perry Nuclear Power Plant. The NRC
noted that the plant continues to operate safely. The increased oversight will
include an extensive NRC team inspection to access the equipment problems and
FirstEnergys corrective actions. The outcome of this increased oversight is
not known at this time. On October 20, 2004, FirstEnergy was notified by the SEC that the
previously disclosed informal inquiry initiated by the SECs Division of
Enforcement in September 2003 relating to the restatements in August 2003 of
previously reported results by FirstEnergy and TE and the Davis-Besse extended
outage has become the subject of a formal order of investigation. The SECs
formal order of investigation also encompasses issues raised during the SECs
examination of FirstEnergy and the Companies under the PUHCA. Concurrent with
this notification, FirstEnergy received a subpoena asking for background
documents and documents related to the restatements and Davis-Besse issues.
FirstEnergy has cooperated fully with the informal inquiry and will continue to
do so with the formal investigation. If it were ultimately determined that FirstEnergy or its subsidiaries has
legal liability or is otherwise made subject to liability based on any of the
above matters, it could have a material adverse effect on FirstEnergys or its
subsidiaries financial condition and results of operations. 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, weather-related impacts 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 107




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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 in the first
nine months 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. In the third quarter of 2004, FirstEnergy made a $500 million voluntary
contribution ($13 million funded by TE) to its pension plan. This contribution
will mitigate future funding requirements and significantly reduce the year-end
minimum pension liability that currently reduces TEs accumulated other
comprehensive income by $9 million. 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. 108




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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 2004, 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 September 30, 2004, TE had $505 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 In March 2004, the EITF reached a consensus on the application guidance
for Issue 03-1. EITF 03-1 provides a model for determining when investments in
certain debt and equity securities are considered other than temporarily
impaired. When an impairment is other-than-temporary, the investment must be
measured at fair value and the impairment loss recognized in earnings. The
recognition and measurement provisions of EITF 03-1, which were to be effective
for periods beginning after June 15, 2004, were delayed by the issuance of FSP
EITF 03-1-1 in September 2004. During the period of delay, TE will continue to
evaluate its investments as required by existing authoritative guidance.  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 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, 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. 109




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PENNSYLVANIA POWER COMPANY 
 CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (Unaudited)
 Three Months Ended
    
    Nine Months EndedSeptember 30,
    
    September 30,2004
    
    2003
    
    2004
    
    2003(In thousands)STATEMENTS OF INCOMEOPERATING REVENUES
    
    $
    143,340
    
    
    $
    145,849
    
    
    $
    420,578
    
    
    $
    390,751OPERATING EXPENSES AND TAXES:Fuel
    
    
    6,347
    
    
    
    6,142
    
    
    
    18,408
    
    
    
    15,073Purchased power
    
    
    44,096
    
    
    
    44,761
    
    
    
    136,699
    
    
    
    125,781Nuclear operating costs
    
    
    19,934
    
    
    
    25,448
    
    
    
    55,737
    
    
    
    107,805Other operating costs
    
    
    16,212
    
    
    
    15,051
    
    
    
    45,371
    
    
    
    41,661Provision for depreciation and amortization
    
    
    13,535
    
    
    
    13,461
    
    
    
    40,472
    
    
    
    40,206General taxes
    
    
    6,416
    
    
    
    6,093
    
    
    
    17,538
    
    
    
    18,151Income taxes
    
    
    16,541
    
    
    
    14,990
    
    
    
    46,425
    
    
    
    17,779Total operating expenses and taxes
    
    
    123,081
    
    
    
    125,946
    
    
    
    360,650
    
    
    
    366,456OPERATING INCOME
    
    
    20,259
    
    
    
    19,903
    
    
    
    59,928
    
    
    
    24,295OTHER INCOME
    
    
    745
    
    
    
    430
    
    
    
    2,287
    
    
    
    1,554NET INTEREST CHARGES:Interest expense
    
    
    1,911
    
    
    
    3,788
    
    
    
    7,434
    
    
    
    11,964Allowance for borrowed funds used during construction
    
    
    (1,271
    )
    
    
    (844
    )
    
    
    (3,197
    )
    
    
    (2,172
    )Net interest charges
    
    
    640
    
    
    
    2,944
    
    
    
    4,237
    
    
    
    9,792INCOME BEFORE CUMULATIVE EFFECT OF
ACCOUNTING CHANGE
    
    
    20,364
    
    
    
    17,389
    
    
    
    57,978
    
    
    
    16,057Cumulative effect of accounting change (net of income taxes
of $7,532,000) (Note 2)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    10,618NET INCOME
    
    
    20,364
    
    
    
    17,389
    
    
    
    57,978
    
    
    
    26,675PREFERRED STOCK DIVIDEND REQUIREMENTS
    
    
    639
    
    
    
    639
    
    
    
    1,919
    
    
    
    2,462EARNINGS ON COMMON STOCK
    
    $
    19,725
    
    
    $
    16,750
    
    
    $
    56,059
    
    
    $
    24,213STATEMENTS OF COMPREHENSIVE INCOMENET INCOME
    
    $
    20,364
    
    
    $
    17,389
    
    
    $
    57,978
    
    
    $
    26,675OTHER COMPREHENSIVE INCOME (LOSS):Minimum liability for unfunded retirement benefits
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (20,956
    )Income tax related to other comprehensive income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    8,629Other comprehensive income (loss), net of tax
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (12,327
    )TOTAL COMPREHENSIVE INCOME
    
    $
    20,364
    
    
    $
    17,389
    
    
    $
    57,978
    
    
    $
    14,348
 The preceding Notes to Consolidated Financial Statements as they relate to
Pennsylvania Power Company are an integral part of these statements. 110




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PENNSYLVANIA POWER COMPANY 
 CONSOLIDATED BALANCE SHEETS (Unaudited)
 September 30,
    
    December 31,2004
    
    2003(In thousands)ASSETSUTILITY PLANT:In service
    
    $
    835,904
    
    
    $
    808,637Less-Accumulated provision for depreciation
    
    
    348,842
    
    
    
    324,710487,062
    
    
    
    483,927Construction work in progress-Electric plant
    
    
    91,610
    
    
    
    68,091Nuclear fuel
    
    
    8,841
    
    
    
    360100,451
    
    
    
    68,451587,513
    
    
    
    552,378OTHER PROPERTY AND INVESTMENTS:Nuclear plant decommissioning trusts
    
    
    137,525
    
    
    
    133,867Long-term notes receivable from associated companies
    
    
    33,049
    
    
    
    39,179Other
    
    
    728
    
    
    
    2,195171,302
    
    
    
    175,241CURRENT ASSETS:Cash and cash equivalents
    
    
    38
    
    
    
    40Notes receivable from associated companies
    
    
    554
    
    
    
    399Receivables-Customers (less accumulated provisions of $875,000 and $769,000, respectively,
for uncollectible accounts)
    
    
    43,162
    
    
    
    44,861Associated companies
    
    
    37,898
    
    
    
    24,965Other
    
    
    364
    
    
    
    1,047Materials and supplies, at average cost
    
    
    37,292
    
    
    
    33,918Prepayments and other
    
    
    13,360
    
    
    
    9,383132,668
    
    
    
    114,613DEFERRED CHARGES:Regulatory assets
    
    
    
    
    
    
    27,513Other
    
    
    9,217
    
    
    
    9,6349,217
    
    
    
    37,147$
    900,700
    
    
    $
    879,379CAPITALIZATION AND LIABILITIESCAPITALIZATION:Common stockholders equity-Common stock, $30 par value, authorized 6,500,000 shares-
6,290,000 shares outstanding
    
    $
    188,700
    
    
    $
    188,700Other paid-in capital
    
    
    24,690
    
    
    
    (310
    )Accumulated other comprehensive loss
    
    
    (11,783
    )
    
    
    (11,783
    )Retained earnings
    
    
    87,237
    
    
    
    54,179Total common stockholders equity
    
    
    288,844
    
    
    
    230,786Preferred stock not subject to mandatory redemption
    
    
    39,105
    
    
    
    39,105Long-term debt and other long-term obligations
    
    
    129,921
    
    
    
    130,358457,870
    
    
    
    400,249CURRENT LIABILITIES:Currently payable long-term debt
    
    
    31,724
    
    
    
    93,474Accounts payable-Associated companies
    
    
    61,771
    
    
    
    40,172Other
    
    
    1,373
    
    
    
    1,294Notes payable to associated companies
    
    
    22,123
    
    
    
    11,334Accrued taxes
    
    
    29,392
    
    
    
    27,091Other
    
    
    11,702
    
    
    
    12,840158,085
    
    
    
    186,205NONCURRENT LIABILITIES:Accumulated deferred income taxes
    
    
    88,599
    
    
    
    97,871Accumulated deferred investment tax credits
    
    
    3,296
    
    
    
    3,516Asset retirement obligation
    
    
    136,046
    
    
    
    129,546Retirement benefits
    
    
    44,777
    
    
    
    54,057Regulatory liabilities
    
    
    3,655
    
    
    
    Other
    
    
    8,372
    
    
    
    7,935284,745
    
    
    
    292,925COMMITMENTS, GUARANTEES AND CONTINGENCIES(Note 3)$
    900,700
    
    
    $
    879,379
 The preceding Notes to Consolidated Financial Statements as they relate to
Pennsylvania Power Company are an integral part of these balance sheets. 111




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PENNSYLVANIA POWER COMPANY 
 CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
 Three Months Ended
    
    Nine Months EndedSeptember 30,
    
    September 30,2004
    
    2003
    
    2004
    
    2003(In thousands)CASH FLOWS FROM OPERATING ACTIVITIES:Net income
    
    $
    20,364
    
    
    $
    17,389
    
    
    $
    57,978
    
    
    $
    26,675Adjustments to reconcile net income to net
cash from operating activities-Provision for depreciation and amortization
    
    
    13,535
    
    
    
    13,461
    
    
    
    40,472
    
    
    
    40,206Nuclear fuel and lease amortization
    
    
    4,550
    
    
    
    4,607
    
    
    
    13,546
    
    
    
    11,396Deferred income taxes, net
    
    
    52
    
    
    
    (2,378
    )
    
    
    (1,160
    )
    
    
    1,376Amortization of investment tax credits
    
    
    (553
    )
    
    
    (598
    )
    
    
    (1,692
    )
    
    
    (1,826
    )Cumulative effect of accounting change (Note 2)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (18,150
    )Pension trust contribution
    
    
    (12,934
    )
    
    
    
    
    
    
    (12,934
    )
    
    
    Receivables
    
    
    (30,285
    )
    
    
    (9,122
    )
    
    
    (10,551
    )
    
    
    12,418Materials and supplies
    
    
    (1,078
    )
    
    
    (45
    )
    
    
    (3,374
    )
    
    
    (565
    )Prepayments and other current assets
    
    
    4,164
    
    
    
    5,503
    
    
    
    (3,977
    )
    
    
    (6,975
    )Accounts payable
    
    
    40,306
    
    
    
    1,244
    
    
    
    21,678
    
    
    
    (917
    )Accrued taxes
    
    
    (2,485
    )
    
    
    14,024
    
    
    
    2,301
    
    
    
    22,825Accrued interest
    
    
    (986
    )
    
    
    (2,496
    )
    
    
    (2,415
    )
    
    
    (2,472
    )Other
    
    
    1,353
    
    
    
    3,765
    
    
    
    5,294
    
    
    
    4,336Net cash provided from operating activities
    
    
    36,003
    
    
    
    45,354
    
    
    
    105,166
    
    
    
    88,327CASH FLOWS FROM FINANCING ACTIVITIES:New Financing-Short-term borrowings, net
    
    
    
    
    
    
    8,290
    
    
    
    10,789
    
    
    
    8,290Equity contributions from parent
    
    
    25,000
    
    
    
    
    
    
    
    25,000
    
    
    
    Redemptions and Repayments-Long-term debt
    
    
    (20,508
    )
    
    
    (40,052
    )
    
    
    (63,297
    )
    
    
    (40,669
    )Short-term borrowings, net
    
    
    (11,414
    )
    
    
    
    
    
    
    
    
    
    
    Dividend Payments-Common stock
    
    
    
    
    
    
    (11,000
    )
    
    
    (23,000
    )
    
    
    (37,000
    )Preferred stock
    
    
    (639
    )
    
    
    (639
    )
    
    
    (1,919
    )
    
    
    (2,462
    )Net cash used for financing activities
    
    
    (7,561
    )
    
    
    (43,401
    )
    
    
    (52,427
    )
    
    
    (71,841
    )CASH FLOWS FROM INVESTING ACTIVITIES:Property additions
    
    
    (24,670
    )
    
    
    (12,017
    )
    
    
    (56,080
    )
    
    
    (52,751
    )Contributions to nuclear decommissioning trusts
    
    
    (399
    )
    
    
    (797
    )
    
    
    (1,196
    )
    
    
    (1,196
    )Loan repayments from (loans to) associated companies, net
    
    
    (36
    )
    
    
    9,646
    
    
    
    5,975
    
    
    
    34,259Other
    
    
    (3,337
    )
    
    
    1,215
    
    
    
    (1,440
    )
    
    
    2,021Net cash used for investing activities
    
    
    (28,442
    )
    
    
    (1,953
    )
    
    
    (52,741
    )
    
    
    (17,667
    )Net change in cash and cash equivalents
    
    
    
    
    
    
    
    
    
    
    (2
    )
    
    
    (1,181
    )Cash and cash equivalents at beginning of period
    
    
    38
    
    
    
    41
    
    
    
    40
    
    
    
    1,222Cash and cash equivalents at end of period
    
    $
    38
    
    
    $
    41
    
    
    $
    38
    
    
    $
    41
 The preceding Notes to Consolidated Financial Statements as they relate to
Pennsylvania Power Company are an integral part of these statements. 112




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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 September 30, 2004, and the related
consolidated statements of income, comprehensive income and cash flows for each
of the three-month and nine-month periods ended September 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
November 2, 2004 113




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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 Penn 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 third quarter of 2004 increased to $20
million from $17 million in the third quarter of 2003. For the first nine
months of 2004, earnings on common stock increased to $56 million from $24
million in the same period of 2003. Earnings on common stock in the first nine
months 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. Income before
the cumulative effect was $16 million in the first nine months of 2003.
Increased results in both 2004 periods resulted from lower nuclear operating
costs and reduced net interest charges. Higher operating revenues partially
offset by increased purchased power costs also contributed to the improved
results for the nine-month period. Operating revenues decreased $2.5 million or 1.7% in the third quarter of
2004 from the same period of 2003. Lower revenues resulted principally from a
$3 million decrease in revenues from distribution deliveries  partially
offset by a $1 million increase in wholesale revenues (primarily to FES) due
to increased nuclear generation available for sale. Retail generation sales
were lower in all customer classes in the third quarter of 2004. Lower
deliveries to residential customers resulted from cooler weather in the third
quarter of 2004 compared to the same period of 2003 which reduced air
conditioning loads. Weaker economic conditions are reflected by the decrease
in distribution deliveries to commercial and industrial customers in the third
quarter of 2004. Operating revenues increased $30 million or 7.6% in the first nine months
of 2004 compared with the same period in 2003, principally as a result of a $26
million increase in wholesale revenues (primarily to FES) due to an increase in
nuclear generation and higher retail generation revenues. Sales increased in
all customer sectors for the first nine months of 2004 compared to the same
period of 2003. Increased generation sales and higher unit prices resulted in
a $11 million increase in generation revenues. Distribution deliveries
increased in all customer classes in the first nine months of 2004 compared
with the same period in 2003; but lower unit prices more than offset the effect
of the higher deliveries in that period, resulting in a $5 million decrease in
revenues. Higher deliveries to the steel sector in the first nine months of
2004 were principally responsible for the increase in kilowatt-hour sales to
industrial customers. Changes in electric generation sales and distribution deliveries in the
third quarter and first nine months of 2004 from the same periods of 2003 are
summarized in the following table: Changes in KWH Sales
    
    Three Months
    
    Nine MonthsIncrease (Decrease)Electric Generation:Retail
    
    
    (5.5
    )%
    
    
    3.3
    %Wholesale
    
    
    4.6
    %
    
    
    24.6
    %Total Electric Generation Sales
    
    
    0.4
    %
    
    
    15.2
    %Distribution Deliveries:Residential
    
    
    (1.2
    )%
    
    
    2.1
    %Commercial
    
    
    (3.1
    )%
    
    
    0.6
    %Industrial
    
    
    (12.4
    )%
    
    
    6.9
    %Total Distribution Deliveries
    
    
    (5.6
    )%
    
    
    3.3
    %
 114




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Operating Expenses and Taxes Total operating expenses and taxes decreased $3 million in the third
quarter and $6 million in the first nine 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
    
    Nine Months(In millions)Increase (Decrease)Fuel
    
    $
    
    
    
    $
    3Purchased power
    
    
    (1
    )
    
    
    11Nuclear operating costs
    
    
    (5
    )
    
    
    (52
    )Other operating costs
    
    
    1
    
    
    
    4Total operation and maintenance expenses
    
    
    (5
    )
    
    
    (34
    )General taxes
    
    
    
    
    
    
    (1
    )Income taxes
    
    
    2
    
    
    
    29Total operating expenses and taxes
    
    $
    (3
    )
    
    $
    (6
    )
 Higher fuel costs in the first nine months of 2004, compared with the same
period of 2003, resulted from increased nuclear generation. Purchased power
costs increased in the first nine months of 2004 compared with the same period
of 2003 reflecting higher unit costs and increased kilowatt-hour purchases to
meet higher retail generation requirements. The decrease in nuclear operating
costs was due to the absence of refueling outages in 2004 at Beaver Valley
Unit 1 (65.00% interest), Perry plant (5.24% interest) and Beaver Valley Unit 2
(13.74% interest) in the first, second and third quarters of 2003,
respectively. Net Interest Charges Net interest charges continued to trend lower, decreasing by approximately
$2 million and $6 million in the third quarter and first nine months of 2004,
respectively, from the same periods last year, reflecting mandatory and
optional debt redemptions of $63 million since the end of the third quarter of
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. Penn received a $25 million equity contribution from OE in the
third quarter of 2004. 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 September 30, 2004, Penn had $38,000 of cash and cash equivalents,
compared with $40,000 as of December 31, 2003. The major sources of changes in
these balances are summarized below. Cash Flows From Operating Activities Cash flows provided from operating activities during the third quarter and
first nine months of 2004, compared with the corresponding periods in 2003,
were as follows: 115




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Three Months Ended
    
    Nine Months EndedSeptember 30,
    
    September 30,Operating Cash Flows
    
    2004
    
    2003
    
    2004
    
    2003(In millions)Cash earnings (1)
    
    $
    39
    
    
    $
    36
    
    
    $
    113
    
    
    $
    63Pension trust contribution
    
    
    (13
    )
    
    
    
    
    
    
    (13
    )
    
    
    Working capital and other
    
    
    10
    
    
    
    9
    
    
    
    5
    
    
    
    25Total
    
    $
    36
    
    
    $
    45
    
    
    $
    105
    
    
    $
    88
  (1)
    
    Includes net income, depreciation and
amortization, deferred income taxes, investment tax
credits and major noncash charges. Net cash from operating activities decreased $9 million in the third
quarter of 2004 compared to the same quarter of 2003 primarily due to a $13
million voluntary pension trust contribution. The decrease was partially
offset by a $3 million increase in cash earnings as described above under
Results of Operations. During the first nine months of 2004, net cash from
operating activities increased $17 million due to a $50 million increase in
cash earnings partially offset by a $20 million decrease from changes in
working capital (including changes in accounts receivable, accounts payable and
accrued taxes) and the $13 million pension contribution. Cash Flows From Financing Activities In the third quarter of 2004, net cash used for financing activities
decreased to $8 million from $43 million from the same quarter last year. In
the first nine months of 2004, net cash used for financing activities decreased
to $52 million from $72 million in the same period last year. These decreases
primarily resulted from a $25 million equity contribution from OE in the third
quarter of 2004 and reduced common stock dividends to OE in both periods. Penn had $592,000 of cash and temporary investments (which include
short-term notes receivable from associated companies) and $22 million of
short-term indebtedness as of September 30, 2004. Penn has obtained
authorization from the SEC to incur short-term debt up to its charter limit of
$46 million (including the utility money pool). Penn had the capability to
issue $497 million of additional FMB on the basis of property additions and
retired bonds. Based upon applicable earnings coverage tests, Penn could issue
up to $526 million of preferred stock (assuming no additional debt was issued)
as of September 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 third quarter of 2004 was 1.28%. 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 September
30, 2004 and matures on March 29, 2005. 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 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 Penn. Penns FMB credit rating was upgraded to BBB from
BBB-. On August 26, 2004, S&P stated that a favorable outcome of FirstEnergys
Ohio Rate Stabilization Plan auction process and a favorable resolution of
pending environmental litigation would support a higher ratings outlook, or
possibly a higher rating. S&P noted that a ratings upgrade in 2004 does not
appear likely because those major issues would most likely not be resolved
before the end of 2004. On September 14, 2004, S&P stated that FirstEnergys
voluntary $500 million contribution to its pension plan was credit neutral. Cash Flows From Investing Activities Net cash used for investing activities totaled $28 million in the third
quarter of 2004 compared to $2 million in the same quarter of 2003. The $26
million increase reflects an increase in capital expenditures and a decrease in
loan repayments from associated companies. For the first nine months of 2004,
net cash used for investing activities was $53 116




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##### Table of Contents



million compared to $18 million in the same period of 2003. The $35 million
increase was primarily due to a $28 million decrease in loan repayments from
associated companies. During the fourth quarter of 2004, capital requirements for property
additions and capital leases are expected to be about $26 million, including
$10 million for nuclear fuel. Penn has additional requirements of approximately
$1 million to meet sinking fund requirements for preferred stock and maturing
long-term debt during the remainder of 2004. Those 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 $52
million and $50 million as of September 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 September 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 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. Penns
regulatory assets are expected to continue to be recovered under the provisions
of its regulatory plan. Penns regulatory assets totaled $28 million as of
December 31, 2003. Changes in Penns net regulatory asset components through
September 30, 2004 resulted in net regulatory liabilities of $4 million as of
September 30, 2004. Reliability Initiatives On October 15, 2003, NERC issued a letter to all NERC control areas and
reliability coordinators requesting a review of various reliability practices.
The Company response confirmed that its review was completed and that various
enhancements were underway to current practices. On February 10, 2004, NERC
issued its Recommended Actions to Prevent and Mitigate the Impacts of Future
Cascading Blackouts, a portion of which were directed at the FirstEnergy
companies and broadly focused on initiatives that were recommended for
completion by June 30, 2004. FirstEnergys detailed implementation plan was
endorsed by the NERC Board of Trustees on May 7, 2004. The various initiatives
recommended by NERC were certified as complete by June 30, 2004, with one minor
exception related to reactive testing of certain generators expected to be
completed later in 2004. On April 5, 2004, the U.S.  Canada Power System Outage Task Force issued
a Final Report on the August 14, 2003 power outages. The Final Report contains
46 recommendations to prevent or minimize the scope of future blackouts.
Forty-five of those recommendations relate to broad industry or policy matters
while one relates to activities the Task Force recommended be undertaken by
FirstEnergy, MISO, PJM and ECAR. FirstEnergy completed the Task Force
recommendations that were directed toward FirstEnergy and reported completion
of those activities on June 30, 2004. With respect to each of the foregoing initiatives, FirstEnergy requested
and NERC provided, a technical assistance team of experts to provide ongoing
guidance and assistance in implementing and confirming timely and successful
completion. NERC further assembled an independent verification team to confirm
implementation of the foregoing initiatives required to be completed as of June
30, 2004. The NERC Verification Team reported, on July 14, 2004, that
FirstEnergy has completed the recommended policies, procedures and actions
required to be completed by June 30, 2004 or summer 2004, with exceptions noted
by FirstEnergy. Implementation of the recommendations has not required
incremental material investment or upgrades to existing equipment. 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 117




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##### Table of Contents



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
Penns service reliability performance deteriorated to a point below the level
of service reliability that existed prior to restructuring in Pennsylvania.
Hearings were held in early August 2004. On September 30, 2004, Penn filed a
settlement agreement with the PPUC that addresses the issues related to this
investigation. As part of the settlement, Penn agreed to enhance service
reliability, performance reporting and communications with customers and
together with Met-Ed and Penelec, to collectively maintain their current
spending levels of at least $255 million annually on combined capital and
operation and maintenance expenditures for transmission and distribution for
the years 2005 through 2007. In November 2004, the PPUC accepted the
recommendation of the ALJ approving the settlement. 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 NOV or Compliance Orders to nine
utilities covering 44 power plants, including the W. H. Sammis Plant which is
owned by OE and Penn. In addition, the U.S. Department of Justice filed eight
civil complaints against various investor-owned utilities, which included a
complaint against OE and Penn in the U.S. District Court for the Southern
District of Ohio. These cases are referred to as New Source Review cases. The
NOV and complaint allege violations of the Clean Air Act based on operation and
maintenance of the W. H. Sammis Plant dating back to 1984. The complaint
requests permanent injunctive relief to require the installation of best
available control technology and civil penalties of up to $27,500 per day of
violation. On August 7, 2003, the United States District Court for the Southern
District of Ohio ruled that 11 projects undertaken at the W. H. Sammis Plant
between 1984 and 1998 required pre-construction permits under the Clean Air
Act. The ruling concludes the liability phase of the case, which deals with
applicability of Prevention of Significant Deterioration provisions of the
Clean Air Act. The remedy phase trial to address civil penalties and what, if
any, actions should be taken to further reduce emissions at the plant has been
rescheduled to January 2005 by the Court because the parties are engaged in
meaningful settlement negotiations. The Court indicated, in its August 2003
ruling, that the remedies it may consider and impose involved a much broader,
equitable analysis, requiring the Court to consider air quality, public health,
economic impact, and employment consequences. The Court may also consider the
less than consistent efforts of the EPA to apply and further enforce the Clean
Air Act. The potential penalties that may be imposed, as well as the capital
expenditures necessary to comply with substantive remedial measures that may be
required, could have a material adverse impact on Penn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 September 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. SIPs 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 118




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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. On September 7, 2004, the EPA established new performance standards under
Clean Water Act Section 316(b) for reducing impacts on fish and shellfish from
cooling water intake structures at certain existing large electric generating
plants. The regulations call for reductions in impingement mortality, when
aquatic organisms are pinned against screens or other parts of a cooling water
intake system and entrainment, which occurs when aquatic species are drawn into
a facilitys cooling water system. Penn is conducting comprehensive
demonstration studies, due in 2008, to determine the operational measures,
equipment or restoration activities, if any, necessary for compliance by their
facilities with the performance standards. Penn is unable to predict the
outcome of such studies. Depending on the outcome of such studies, the future
cost of compliance with these standards may be substantial. Power Outages and Related Litigation On August 14, 2003, various states and parts of southern Canada
experienced widespread power outages. The outages affected approximately 1.4
million customers in FirstEnergys service area. On April 5, 2004, the U.S.
Canada Power System Outage Task Force released its final report on the
outages. In the final report, the Task Force concluded, among other things,
that the problems leading to the outages began in FirstEnergys Ohio service
area. Specifically, the final report concludes, among other things, that the
initiation of the August 14, 2003 power outages resulted from an alleged
failure of both FirstEnergy and ECAR to assess and understand perceived
inadequacies within the FirstEnergy system; inadequate situational awareness of
the developing conditions; and a perceived failure to adequately manage tree
growth in certain transmission rights of way. The Task Force also concluded
that there was a failure of the interconnected grids reliability organizations
(MISO and PJM) to provide effective diagnostic support. The final report is
publicly available through the Department of Energys website (www.doe.gov).
FirstEnergy believes that the final report does not provide a complete and
comprehensive picture of the conditions that contributed to the August 14, 2003
power outages and that it does not adequately address the underlying causes of
the outages. FirstEnergy remains convinced that the outages cannot be explained
by events on any one utilitys system. The final report contains 46
recommendations to prevent or minimize the scope of future blackouts.
Forty-five of those recommendations relate to broad industry or policy matters
while one, including subparts, relates to activities the Task Force recommends
be undertaken by FirstEnergy, MISO, PJM, and ECAR. FirstEnergy implemented
several initiatives, both prior to and since the August 14, 2003 power outages,
which are consistent with these and other recommendations and collectively
enhance the reliability of its electric system. FirstEnergy certified to NERC
on June 30, 2004, completion of various reliability recommendations and further
received independent verification of completion status from a NERC verification
team on July 14, 2004 (see 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 September 30, 2004 for any expenditures in excess of
those actually incurred through that date. FirstEnergy is vigorously defending these actions, but cannot predict the
outcome of any of these proceedings or whether any further regulatory
proceedings or legal actions may be instituted against the Companies. In
particular, if FirstEnergy or its subsidiaries were ultimately determined to
have legal liability in connection with these proceedings, it could have a
material adverse effect on FirstEnergys or its subsidiaries financial
condition and results of operations. 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 herein. On August 12, 2004, the NRC publicly disclosed that it was notifying
FirstEnergy that it will increase its regulatory oversight of the Perry Nuclear
Power Plant as a result of problems with safety system equipment over the past
two years. Penn owns a 5.24% interest in the Perry Nuclear Power Plant. The NRC
noted that the plant continues to operate safely. The increased oversight will
include an extensive NRC team inspection to access the equipment problems and
FirstEnergys corrective actions. The outcome of this increased oversight is
not known at this time. 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 119




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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. 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, demand by
customer class, weather-related impacts and electricity provided by alternative
suppliers. Pension and Other Postretirement Benefits Accounting FirstEnergys pension and postretirement 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 in the first
nine months 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. In the third quarter of 2004, FirstEnergy made a $500 million voluntary
contribution ($13 million funded by Penn) to its pension plan. This
contribution will mitigate future funding requirements and significantly reduce
the year-end minimum pension liability that currently reduces Penns
accumulated other comprehensive income by $12 million. 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. 120




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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
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 In March 2004, the EITF reached a consensus on the application guidance
for Issue 03-1. EITF 03-1 provides a model for determining when investments in
certain debt and equity securities are considered other than temporarily
impaired. When an impairment is other-than-temporary, the investment must be
measured at fair value and the impairment loss recognized in earnings. The
recognition and measurement provisions of EITF 03-1, which were to be effective
for periods beginning after June 15, 2004, were delayed by the issuance of FSP
EITF 03-1-1 in September 2004.  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. 121




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JERSEY CENTRAL POWER & LIGHT COMPANY 
 CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited) Three Months Ended
    
    Nine Months EndedSeptember 30,
    
    September 30,2004
    
    2003
    
    2004
    
    2003Restated
    
    
    
    
    
    Restated(See Note 2)
    
    
    
    
    
    (See Note 2)(In thousands)STATEMENTS OF INCOMEOPERATING REVENUES
    
    $
    706,613
    
    
    $
    741,293
    
    
    $
    1,754,402
    
    
    $
    1,941,016OPERATING EXPENSES AND TAXES:Purchased power
    
    
    387,282
    
    
    
    389,124
    
    
    
    943,757
    
    
    
    1,175,310Other operating costs
    
    
    91,516
    
    
    
    103,797
    
    
    
    259,176
    
    
    
    255,118Provision for depreciation and amortization
    
    
    102,706
    
    
    
    95,519
    
    
    
    273,308
    
    
    
    266,788General taxes
    
    
    17,901
    
    
    
    18,506
    
    
    
    48,571
    
    
    
    47,282Income taxes
    
    
    35,099
    
    
    
    46,815
    
    
    
    70,555
    
    
    
    55,378Total operating expenses and taxes
    
    
    634,504
    
    
    
    653,761
    
    
    
    1,595,367
    
    
    
    1,799,876OPERATING INCOME
    
    
    72,109
    
    
    
    87,532
    
    
    
    159,035
    
    
    
    141,140OTHER INCOME
    
    
    1,996
    
    
    
    557
    
    
    
    4,603
    
    
    
    3,997NET INTEREST CHARGES:Interest on long-term debt
    
    
    21,709
    
    
    
    20,888
    
    
    
    62,240
    
    
    
    66,867Allowance for borrowed funds used during construction
    
    
    (169
    )
    
    
    39
    
    
    
    (440
    )
    
    
    (195
    )Deferred interest
    
    
    (871
    )
    
    
    (1,541
    )
    
    
    (2,685
    )
    
    
    (7,667
    )Other interest expense
    
    
    1,105
    
    
    
    1,131
    
    
    
    1,958
    
    
    
    1,076Subsidiarys preferred stock dividend requirements
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    5,348Net interest charges
    
    
    21,774
    
    
    
    20,517
    
    
    
    61,073
    
    
    
    65,429NET INCOME
    
    
    52,331
    
    
    
    67,572
    
    
    
    102,565
    
    
    
    79,708PREFERRED STOCK DIVIDEND REQUIREMENTS
    
    
    125
    
    
    
    125
    
    
    
    375
    
    
    
    (238
    )EARNINGS ON COMMON STOCK
    
    $
    52,206
    
    
    $
    67,447
    
    
    $
    102,190
    
    
    $
    79,946STATEMENTS OF COMPREHENSIVE INCOMENET INCOME
    
    $
    52,331
    
    
    $
    67,572
    
    
    $
    102,565
    
    
    $
    79,708OTHER COMPREHENSIVE INCOME:Minimum liability for unfunded retirement benefits
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (103,420
    )Unrealized gain (loss) on derivative hedges
    
    
    172
    
    
    
    118
    
    
    
    217
    
    
    
    (3,188
    )Unrealized loss on available for sale securities
    
    
    
    
    
    
    
    
    
    
    (5
    )
    
    
    Other comprehensive income (loss)
    
    
    172
    
    
    
    118
    
    
    
    212
    
    
    
    (106,608
    )Income tax related to other comprehensive income
    
    
    1,543
    
    
    
    
    
    
    
    1,543
    
    
    
    42,733Other comprehensive income (loss), net of tax
    
    
    1,715
    
    
    
    118
    
    
    
    1,755
    
    
    
    (63,875
    )TOTAL COMPREHENSIVE INCOME
    
    $
    54,046
    
    
    $
    67,690
    
    
    $
    104,320
    
    
    $
    15,833
 The preceding Notes to Consolidated Financial Statements as they relate to
Jersey Central Power & Light Company are an integral part of these statements. 122




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JERSEY CENTRAL POWER & LIGHT COMPANY 
 CONSOLIDATED BALANCE SHEETS
(Unaudited) September 30,
    
    December 31,2004
    
    2003(In thousands)ASSETSUTILITY PLANT:In service
    
    $
    3,700,645
    
    
    $
    3,642,467Less-Accumulated provision for depreciation
    
    
    1,364,448
    
    
    
    1,367,0422,336,197
    
    
    
    2,275,425Construction work in progress
    
    
    66,046
    
    
    
    48,9852,402,243
    
    
    
    2,324,410OTHER PROPERTY AND INVESTMENTS:Nuclear plant decommissioning trusts
    
    
    130,185
    
    
    
    125,945Nuclear fuel disposal trust
    
    
    159,047
    
    
    
    155,774Long-term notes receivable from associated companies
    
    
    20,701
    
    
    
    19,579Other
    
    
    18,323
    
    
    
    18,744328,256
    
    
    
    320,042CURRENT ASSETS:Cash and cash equivalents
    
    
    277
    
    
    
    271Receivables-Customers (less accumulated provisions of $4,536,000 and $4,296,000,
respectively, for uncollectible accounts)
    
    
    273,931
    
    
    
    198,061Associated companies
    
    
    28,426
    
    
    
    70,012Other (less accumulated provisions of $782,000 and $1,183,000,
respectively, for uncollectible accounts)
    
    
    39,034
    
    
    
    46,411Materials and supplies, at average cost
    
    
    2,069
    
    
    
    2,480Prepayments and other
    
    
    27,947
    
    
    
    49,360371,684
    
    
    
    366,595DEFERRED CHARGES:Regulatory assets
    
    
    2,147,327
    
    
    
    2,558,214Goodwill
    
    
    1,995,759
    
    
    
    2,001,302Other
    
    
    4,535
    
    
    
    8,4814,147,621
    
    
    
    4,567,997$
    7,249,804
    
    
    $
    7,579,044CAPITALIZATION AND LIABILITIESCAPITALIZATION:Common stockholders equity-Common stock, $10 par value, authorized 16,000,000 shares -
15,371,270 shares outstanding
    
    $
    153,713
    
    
    $
    153,713Other paid-in capital
    
    
    3,022,333
    
    
    
    3,029,894Accumulated other comprehensive loss
    
    
    (50,010
    )
    
    
    (51,765
    )Retained earnings
    
    
    64,322
    
    
    
    22,132Total common stockholders equity
    
    
    3,190,358
    
    
    
    3,153,974Preferred stock not subject to mandatory redemption
    
    
    12,649
    
    
    
    12,649Long-term debt
    
    
    1,244,249
    
    
    
    1,095,9914,447,256
    
    
    
    4,262,614CURRENT LIABILITIES:Currently payable long-term debt
    
    
    16,700
    
    
    
    175,921Notes payable to associated companies
    
    
    158,337
    
    
    
    230,985Accounts payable-Associated companies
    
    
    76,713
    
    
    
    42,410Other
    
    
    129,942
    
    
    
    105,815Accrued taxes
    
    
    36,763
    
    
    
    919Accrued interest
    
    
    26,324
    
    
    
    14,843Other
    
    
    38,915
    
    
    
    58,094483,694
    
    
    
    628,987NONCURRENT LIABILITIES:Accumulated deferred income taxes
    
    
    584,254
    
    
    
    640,208Accumulated deferred investment tax credits
    
    
    6,521
    
    
    
    7,711Power purchase contract loss liability
    
    
    1,261,414
    
    
    
    1,473,070Nuclear fuel disposal costs
    
    
    169,301
    
    
    
    167,936Asset retirement obligation
    
    
    71,572
    
    
    
    109,851Retirement benefits
    
    
    90,840
    
    
    
    159,219Other
    
    
    134,952
    
    
    
    129,4482,318,854
    
    
    
    2,687,443COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 3)$
    7,249,804
    
    
    $
    7,579,044
 The preceding Notes to Consolidated Financial Statements as they relate to
Jersey Central Power & Light Company are an integral part of these balance
sheets. 123




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JERSEY CENTRAL POWER & LIGHT COMPANY 
 CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited) Three Months Ended
    
    Nine Months EndedSeptember 30,
    
    September 30,2004
    
    2003
    
    2004
    
    2003Restated
    
    
    
    
    
    Restate(See Note 2)
    
    
    
    
    
    (See Note 2)(In thousands)CASH FLOWS FROM OPERATING ACTIVITIES:Net income
    
    $
    52,331
    
    
    $
    67,572
    
    
    $
    102,565
    
    
    $
    79,708Adjustments to reconcile net income to net
cash from operating activities-Provision for depreciation and amortization
    
    
    102,706
    
    
    
    95,519
    
    
    
    273,308
    
    
    
    266,788Deferred costs, net
    
    
    (77,162
    )
    
    
    (61,000
    )
    
    
    (155,552
    )
    
    
    (203,452
    )Deferred income taxes, net
    
    
    6,561
    
    
    
    7,362
    
    
    
    (12,392
    )
    
    
    (9,642
    )Investment tax credits, net
    
    
    (396
    )
    
    
    (557
    )
    
    
    (1,190
    )
    
    
    (1,707
    )Disallowed regulatory assets (see Note 6)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    152,500Pension trust contribution
    
    
    (62,499
    )
    
    
    
    
    
    
    (62,499
    )
    
    
    Receivables
    
    
    (34,749
    )
    
    
    (30,971
    )
    
    
    (26,906
    )
    
    
    (98,573
    )Materials and supplies
    
    
    64
    
    
    
    37
    
    
    
    411
    
    
    
    (735
    )Prepayments and other current assets
    
    
    21,136
    
    
    
    49,888
    
    
    
    21,413
    
    
    
    (20,559
    )Accounts payable
    
    
    57,485
    
    
    
    (105,130
    )
    
    
    58,430
    
    
    
    (92,791
    )Accrued taxes
    
    
    (27,924
    )
    
    
    13,633
    
    
    
    35,844
    
    
    
    19,753Accrued interest
    
    
    16,709
    
    
    
    7,391
    
    
    
    11,481
    
    
    
    (1,037
    )Accrued retirement benefit obligation
    
    
    2,888
    
    
    
    22,739
    
    
    
    (5,880
    )
    
    
    28,905NUG power contract restructuring
    
    
    52,800
    
    
    
    
    
    
    
    52,800
    
    
    
    Revenue credits to
customers
    
    
    
    
    
    
    (19,583
    )
    
    
    
    
    
    
    (71,984
    )Other
    
    
    (10,123
    )
    
    
    (33,783
    )
    
    
    (17,184
    )
    
    
    19,274Net cash provided from operating activities
    
    
    99,827
    
    
    
    13,117
    
    
    
    274,649
    
    
    
    66,448CASH FLOWS FROM FINANCING ACTIVITIES:New Financing-Long-term debt
    
    
    
    
    
    
    
    
    
    
    300,000
    
    
    
    150,000Short-term borrowings, net
    
    
    
    
    
    
    91,741
    
    
    
    
    
    
    
    287,867Redemptions and Repayments-Preferred stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (125,244
    )Long-term debt
    
    
    (7,082
    )
    
    
    (82,388
    )
    
    
    (304,150
    )
    
    
    (247,414
    )Short-term borrowings, net
    
    
    (456
    )
    
    
    
    
    
    
    (72,648
    )
    
    
    Dividend Payments-Common stock
    
    
    (40,000
    )
    
    
    
    
    
    
    (60,000
    )
    
    
    (128,000
    )Preferred stock
    
    
    (125
    )
    
    
    
    
    
    
    (375
    )
    
    
    Net cash provided from (used for) financing activities
    
    
    (47,663
    )
    
    
    9,353
    
    
    
    (137,173
    )
    
    
    (62,791
    )CASH FLOWS FROM INVESTING ACTIVITIES:Property additions
    
    
    (52,507
    )
    
    
    (25,654
    )
    
    
    (135,932
    )
    
    
    (83,714
    )Decommissioning trust investments
    
    
    (724
    )
    
    
    (742
    )
    
    
    (2,171
    )
    
    
    (1,931
    )Loan repayments from (loans to) associated companies, net
    
    
    (711
    )
    
    
    (984
    )
    
    
    (1,122
    )
    
    
    76,374Other
    
    
    1,773
    
    
    
    153
    
    
    
    1,755
    
    
    
    2,061Net cash used for investing activities
    
    
    (52,169
    )
    
    
    (27,227
    )
    
    
    (137,470
    )
    
    
    (7,210
    )Net increase (decrease) in cash and cash equivalents
    
    
    (5
    )
    
    
    (4,757
    )
    
    
    6
    
    
    
    (3,553
    )Cash and cash equivalents at beginning of period
    
    
    282
    
    
    
    6,027
    
    
    
    271
    
    
    
    4,823Cash and cash equivalents at end of period
    
    $
    277
    
    
    $
    1,270
    
    
    $
    277
    
    
    $
    1,270
 The preceding Notes to Consolidated Financial Statements as they relate to
Jersey Central Power & Light Company are an integral part of these statements. 124




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##### Table of Contents



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 September 30, 2004, and the
related consolidated statements of income, comprehensive income and cash flows
for each of the three-month and nine-month periods ended September 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 nine-month periods ended September 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
November 2, 2004 125




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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
conducts business in northern, western and east central New Jersey, providing
regulated transmission and distribution services. JCP&L also provides
generation services to those customers electing to retain JCP&L as their power
supplier. JCP&L has unbundled the price for electricity into its component
elements  including generation, transmission, distribution and transition
charges. Restatements of Previously Reported Quarterly Results As discussed in Note 2 to the Consolidated Financial Statements, JCP&Ls
results for the third quarter and first nine 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 $5.8 million ($3.4 million after-tax) and $9.0 million
($5.3 million after-tax) in the third quarter of 2003 and the first nine months
of 2003, respectively. 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 third quarter of 2004 decreased to $52
million from $67 million in the third quarter of 2003. For the first nine
months of 2004, earnings on common stock increased to $102 million from $80
million in the same period of 2003. Earnings in the third quarter and the
first nine months of 2003 included non-cash charges aggregating $13 million ($8
million after-tax) and $172 million ($103 million after tax), respectively, due
to a rate case decision disallowing cost recovery (see Regulatory Matters).
Earnings before the non-cash charges were $75 million and $183 million for the
third quarter and the first nine months of 2003, respectively. The decrease in
earnings excluding the non-cash charges in 2003 was primarily due to lower
operating revenues in both periods which were partially offset by lower other
operating costs in the third quarter of 2004 and lower purchased power costs in
the first nine months of 2004 compared to the same periods of 2003. Operating revenues decreased by $35 million or 4.7% in the third quarter
of 2004 from the same period of 2003 principally from lower retail generation
and distribution throughput revenues and a $1 million decrease in wholesale
sales revenues. Retail generation sales decreased by 12.4% due to an 8.3
percentage point increase in electric generation services provided by
alternative suppliers as a percent of total sales deliveries in JCP&Ls
franchise area. Lower retail generation sales were partially offset by higher
unit prices reflecting the results of the BGS auction (see Regulatory Matters)
resulting in a combined $11 million decrease in revenues. Operating revenues
decreased $187 million or 9.6% in the first nine months of 2004, compared with
the same period in 2003, reflecting decreased retail generation sales and
distribution throughput revenues and a $56 million decrease in wholesale
revenues. JCP&L entered into long-term power purchase agreements in connection
with the divestiture of its generation facilities and sold 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 subsequently decreased. Retail generation sales decreased by
18.6% in the first nine months of 2004 reflecting the same trend in customer
shopping (increases of 4.5, 22.2 and 56.2 percentage points for residential,
commercial and industrial customers, respectively). The impact of lower retail
generation sales was partially offset by higher unit prices resulting in a $10
million decrease in retail generation revenues. Revenues from distribution throughput decreased by $21 million in the
third quarter of 2004 as compared to the third quarter of 2003. Distribution
deliveries to residential customers decreased 3.1% due to cooler weather which
reduced air conditioning loads. Weaker economic conditions reduced
distribution deliveries to commercial and industrial customers in the third
quarter of 2004 compared to the same period in 2003. The decreased distribution
deliveries coupled with lower unit prices reduced revenues from electricity
throughput by $21 million in the third quarter of 2004. The increase in
distribution deliveries for the first nine months of 2004 resulted from higher
deliveries to the residential (3.0%) and commercial (1.5%) sectors. Lower unit
prices offset the increased volume sales resulting in a $114 million decrease
in distribution revenues. 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. Partially offsetting the
lower base distribution rates were higher energy, MTC and SBC rates, with the
increase in energy and MTC rates concentrated in the summer billing months.
These did not result in material earnings impact due to deferral accounting. 126




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Changes in distribution deliveries in the third quarter and first nine
months of 2004 compared with the same periods of 2003 are summarized in the
following table: Changes in KWH Deliveries
    
    Three Months
    
    Nine MonthsIncrease (Decrease)Residential
    
    
    (3.1
    )%
    
    
    3.0
    %Commercial
    
    
    (2.8
    )%
    
    
    1.5
    %Industrial
    
    
    (5.1
    )%
    
    
    (0.3
    )%Total Distribution Deliveries
    
    
    (3.4
    )%
    
    
    1.8
    %
 Operating Expenses and Taxes Total operating expenses and taxes decreased by $19 million in the third
quarter and $205 million in the first nine 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
    
    Nine MonthsIncrease (Decrease)
    
    (In millions)Purchased power costs
    
    $
    (2
    )
    
    $
    (231
    )Other operating costs
    
    
    (12
    )
    
    
    4Total operation and maintenance expenses
    
    
    (14
    )
    
    
    (227
    )Provision for depreciation and amortization
    
    
    7
    
    
    
    6General taxes
    
    
    
    
    
    
    1Income taxes
    
    
    (12
    )
    
    
    15Total in operating expenses and taxes
    
    $
    (19
    )
    
    $
    (205
    )
 Purchased power costs and the provision for depreciation and amortization
in 2003 included non-cash charges for amounts disallowed in the July 2003 JCP&L
rate case decision (see Regulatory Matters)  $153 million of deferred
purchased power costs and $19 million charged to depreciation and amortization
in the first nine months of 2004. Excluding the disallowed deferred energy
costs in the second quarter of 2003, purchased power costs decreased by $2
million in the third quarter and $78 million in the first nine months of 2004
from the same periods of 2003. Purchased power costs in both periods reflected
lower kilowatt-hour purchases due to reduced generation sales requirements,
partially offset by higher unit prices from changes in deferred energy and
capacity costs. The decrease in other operating costs of $12 million in the
third quarter of 2004 is attributable to lower payroll and employee benefits
costs and the absence in 2004 of storm restoration costs incurred in the third
quarter of 2003. Other operating costs increased $4 million for the first nine
months of 2004 due to JCP&Ls accelerated reliability program. Excluding the
amounts disallowed in the July 2003 rate decision ($13 million and $19 million
in the third quarter and first nine months of 2003, respectively), depreciation
and amortization increased $20 million and $25 million in the third quarter and
the first nine months of 2004, respectively, reflecting an increased level of
regulatory asset amortization associated with higher MTC and SBC revenues,
partially offset by lower depreciation rates. Net Interest Charges Net interest charges for the 2004 periods reflect reductions associated
with debt redeemed since the end of the third quarter of 2003. Interest
expense in the third quarter of 2004 included a $2 million adjustment relating
to $300 million of notes issued in April 2004 that increased net interest
charges for the period. 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 JCP&Ls cash and cash equivalents were $0.3 million as of September 30,
2004 and December 31, 2003. Cash Flows From Operating Activities Cash provided from operating activities during the third quarter and first
nine months of 2004, compared to the corresponding periods of 2003, were as
follows: 127




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Three Months Ended
    
    Nine Months EndedSeptember 30,
    
    September 30,Operating Cash Flows
    
    2004
    
    2003
    
    2004
    
    2003(In millions)Cash earnings (1)
    
    $
    84
    
    
    $
    109
    
    
    $
    207
    
    
    $
    284Pension trust contribution
    
    
    (62
    )
    
    
    
    
    
    
    (62
    )
    
    
    Working capital and other
    
    
    78
    
    
    
    (96
    )
    
    
    130
    
    
    
    (218
    )Total
    
    $
    100
    
    
    $
    13
    
    
    $
    275
    
    
    $
    66
  (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 third
quarter of 2004 compared to the same period in 2003. The increase included a
$174 million increase from changes in working capital, partially offset by a
$62 million voluntary pension trust contribution and a $25 million decrease in
cash earnings as described under Results of Operations. The change in working
capital primarily reflects an increase in accounts payable and $52.8 million
received in connection with restructuring a NUG power contract. Net cash from
operating activities increased $209 million in the first nine months of 2004
compared to the same period in 2003 due to a $348 million increase from changes
in working capital, partially offset by a $77 million decrease in cash earnings
and the $62 million pension contribution. The change in working capital
primarily reflects lower accounts receivable and prepayments and higher
accounts payable and accrued tax balances. Cash Flows From Financing Activities Net cash used for financing activities in the third quarter of 2004 was
$48 million compared to net cash provided from financing activities of $9
million in the third quarter of 2003. The change primarily reflects a $40
million increase in common stock dividends to FirstEnergy and a $17 million
increase in net debt and preferred stock redemptions. Net cash used for
financing activities increased to $137 million in the first nine months of 2004
compared to $63 million in the same period of 2003. The increase resulted from
a $142 million increase in net debt and preferred stock redemptions, partially
offset by a $68 million decrease in common stock dividends to FirstEnergy. JCP&L has obtained authorization from the SEC to incur short-term debt up
to its charter limit of $419 million (including the utility money pool). JCP&L
may issue FMB on the basis of property additions and retired bonds under the
terms of its mortgage indenture, provided, however, that under a provision of
its senior note indenture, JCP&L may issue additional FMB only as collateral
for senior notes. As of September 30, 2004, JCP&L had the capability to issue
$490 million of additional senior notes upon the basis of FMB collateral. Based
upon applicable earnings coverage tests, JCP&L could issue a total of $406
million of preferred stock (assuming no additional debt was issued) as of
September 30, 2004. 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
third quarter of 2004 was 1.28%. JCP&L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 such securities is stable. 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. On August 26, 2004, S&P stated that a favorable outcome of FirstEnergys
Ohio Rate Stabilization Plan auction process and a favorable resolution of
pending environmental litigation would support a higher ratings outlook, or
possibly a higher rating. S&P noted that a ratings upgrade in 2004 does not
appear likely because those major issues would most likely not be resolved
before the end of 2004. On September 14, 2004, S&P stated that FirstEnergys
$500 million voluntary contribution to its pension plan was credit neutral. Cash Flows From Investing Activities Net cash used for investing activities totaled $52 million and $137
million in the third quarter and first nine months of 2004, respectively,
compared to $27 million and $7 million in the respective periods of 2003. The
change in both periods was due to a decrease in loan repayments from associated
companies and higher capital expenditures in 2004. 128




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##### Table of Contents



During the fourth quarter of 2004, capital requirements for property
additions are expected to be about $27 million. JCP&L has additional
requirements of approximately $5 million for maturing long-term debt during the
remainder of 2004. Those 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 third quarter and first nine months of
2004 is summarized in the following table: Increase (Decrease) in the Fair Value
    
    Three Months Ended
    
    Nine Months Endedof Commodity Derivative Contracts
    
    September 30, 2004
    
    September 30, 2004Non-Hedge
    
    Hedge
    
    Total
    
    Non-Hedge
    
    Hedge
    
    Total(In millions)Change in the Fair Value of Commodity Derivative ContractsNet asset at beginning of period
    
    $
    15
    
    
    $
    
    
    
    $
    15
    
    
    $
    16
    
    
    $
    
    
    
    $
    16New contract value when entered
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Changes in value of existing contracts
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (1
    )
    
    
    
    
    
    
    (1
    )Change in techniques/assumptions
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Settled contracts
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Net Assets  Derivative Contracts as of September 30, 2004(1)
    
    $
    15
    
    
    $
    
    
    
    $
    15
    
    
    $
    15
    
    
    $
    
    
    
    $
    15Impact of Changes in Commodity Derivative Contracts(2)Income Statement Effects (Pre-Tax)
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    (1
    )
    
    $
    
    
    
    $
    (1
    )Balance Sheet Effects:Other Comprehensive Income (Pre-Tax)
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    Regulatory Liability
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    
  (1) Includes $15 million in non-hedge commodity derivative contracts which
are offset by a regulatory liability.(2) Represents the increase in value of existing contracts, settled contracts
and changes in techniques/assumptions. Derivatives included on the Consolidated Balance Sheet as of September 30,
2004: Non-Hedge
    
    Hedge
    
    Total(In millions)Current-Other Assets
    
    $
    
    
    
    $
    
    
    
    $
    Other Liabilities
    
    
    
    
    
    
    
    
    
    
    Non-Current-Other Deferred Charges
    
    
    15
    
    
    
    
    
    
    
    15Other 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, 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: Source of Information Fair Value by Contract Year
    
    2004(1)
    
    2005
    
    2006
    
    2007
    
    Thereafter
    
    Total(In millions)Prices based on external sources(2)
    
    $
    2
    
    
    $
    3
    
    
    $
    3
    
    
    $
    
    
    
    $
    
    
    
    $
    8Prices based on models
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2
    
    
    
    5
    
    
    
    7Total(3)
    
    $
    2
    
    
    $
    3
    
    
    $
    3
    
    
    $
    2
    
    
    $
    5
    
    
    $
    15
 (1) For the last quarter of 2004.(2) Broker quote sheets.(3) Includes $15 million from an embedded option that is offset by a regulatory
liability and does not affect earnings. 129




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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
September 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 $73
million and $69 million as of September 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 September 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 transmission and distribution systems, which
remain 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. On July 25, 2003, the NJBPU announced its JCP&L base
electric rate proceeding decision, which reduced JCP&Ls annual revenues by
approximately $62 million effective August 1, 2003. The NJBPU decision also
provided for an interim return on equity of 9.5% on JCP&Ls rate base for the
subsequent six to twelve months. During that period, the decision also required
that, within approximately one year of its issuance, JCP&L would initiate
another proceeding to request recovery of additional costs incurred to enhance
system reliability. In that Phase II proceeding, the NJBPU could increase
JCP&Ls return on equity to 9.75% or decrease it to 9.25%, depending on its
assessment of the reliability of JCP&Ls service. Any reduction would be
retroactive to August 1, 2003. The net revenue decrease from the NJBPUs
decision consists of a $223 million decrease in the electricity delivery
charge, a $111 million increase due to the August 1, 2003 expiration of annual
customer credits previously mandated by the New Jersey transition legislation,
a $49 million increase in the MTC tariff component, and a net $1 million
increase in the SBC. The decision in the deferred balances proceeding
disallowed $153 million of deferred energy costs, so that the MTC allows for
the recovery of $465 million in deferred energy costs over the next ten years
on an interim basis. As a result, JCP&L recorded charges to net income for the
year ended December 31, 2003, aggregating $185 million ($109 million net of
tax) consisting of the $153 million of disallowed deferred energy costs and $32
million of other disallowed regulatory assets. JCP&L filed an interim motion
for rehearing and reconsideration with the NJBPU on August 15, 2003 with
respect to the following issues: (1) the disallowance of the $153 million
deferred energy costs; (2) the reduced rate of return on equity; and (3) $42.7
million of disallowed costs to achieve merger savings. In its final decision
and order issued on May 17, 2004, the NJPBU clarified the method for
calculating interest attributable to the cost disallowances, resulting in a
$5.4 million reduction from the amount estimated in 2003. On June 1, 2004,
JCP&L filed with the NJBPU a supplemental and amended motion for rehearing and
reconsideration. On July 7, 2004, the NJBPU granted limited reconsideration and
rehearing on the following issues: (1) deferred cost disallowances, (2) the
capital structure including the rate of return, (3) merger savings, including
amortization of costs to achieve merger savings; and (4) decommissioning. All
other issues included in JCP&Ls amended motion were denied. Oral arguments
were held on August 4, 2004. Management is unable to predict when a decision
may be reached by the NJBPU. On July 5, 2003, JCP&L experienced a series of 34.5 kilovolt
sub-transmission line faults that resulted in outages on the New Jersey shore.
The NJBPU instituted an investigation into these outages, and directed that a
Special Reliability Master (SRM) be hired to oversee the investigation. On
December 8, 2003, the SRM issued his Interim Report recommending that JCP&L
implement a series of actions to improve reliability in the area affected by
the outages. The NJBPU adopted the findings and recommendations of the Interim
Report on December 17, 2003, and ordered JCP&L to implement the recommended
actions on a staggered basis, with initial actions to be completed by March 31,
2004. In late 2003, in accordance with a Settlement Stipulation concerning an
August 2002 storm outage, the NJBPU engaged Booth & Associates to conduct an
audit of the planning, operations and maintenance practices, policies and
procedures of JCP&L. The audit was expanded to include the July 2003 outage and
was completed in January 2004. On June 9, 2004, the NJBPU approved a
stipulation that incorporated the final SRM report and portions of the final
Booth report. The final order was issued by the NJBPU on July 23, 2004. On July 16, 2004, JCP&L filed the Phase II rate filing with the NJBPU
which requested an increase in base rates of $36 million, reflecting the
recovery of system reliability costs and a 9.75% return on equity. The filing
also 130




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requests an increase to the MTC deferred balance recovery of approximately $20
million annually. Discovery/settlement conferences are ongoing. The filing
fulfills the NJBPU requirement that a Phase II proceeding be conducted and that
any expenditures and projects undertaken by JCP&L to increase its system
reliability be reviewed. JCP&L sells all self-supplied energy (NUGs and owned generation) to the
wholesale market with offsetting credits to its deferred energy balances with
the exception of 300 MW from JCP&Ls must run NUG committed supply currently
being used to serve BGS customers pursuant to NJBPU order. The BGS auction for
periods beginning June 1, 2004 was completed in February 2004 and new BGS
tariffs reflecting the auction results became effective June 1, 2004. On May
25, 2004, the NJBPU issued an order adopting a schedule for the BGS post
transition year three process. JCP&L filed its proposal suggesting how BGS
should be procured for year three and beyond. The NJBPU decision on the filing
was announced on October 22, 2004, approving with minor modifications the BGS
procurement process filed by JCP&L and the other New Jersey electric
distribution companies and authorizing the continued use of NUG committed
supply to serve 300 MW of BGS load. The auction is scheduled to take place in
February 2005 for the supply period beginning June 1, 2005. In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on
June 7, 2004 supporting a continuation of the current level and duration of the
funding of TMI-2 decommissioning costs by New Jersey ratepayers without a
reduction, termination or capping of the funding. On September 30, 2004, JCP&L
filed an updated TMI-2 decommissioning study prepared by TLG Services, Inc.
(see Note 2  Asset Retirement Obligations). This study resulted in an updated
total decommissioning cost estimate of $729 million (in 2003 dollars) compared
to the estimated $528 million (in 2003 dollars) from the prior 1995
decommissioning study. 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
$2.1 billion and $2.6 billion as of September 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 are 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 September 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 Outages and Related Litigation On August 14, 2003, various states and parts of southern Canada
experienced widespread power outages. The outages affected approximately 1.4
million customers in FirstEnergys service area. On April 5, 2004, the U.S.
Canada Power System Outage Task Force released its final report on the
outages. In the final report, the Task Force concluded, among other things,
that the problems leading to the outages began in FirstEnergys Ohio service
area. Specifically, the final report concludes, among other things, that the
initiation of the August 14, 2003 power outages resulted from an alleged
failure of both FirstEnergy and ECAR to assess and understand perceived
inadequacies within the FirstEnergy system; inadequate situational awareness of
the developing conditions; and a perceived failure to adequately manage tree
growth in certain transmission rights of way. The Task Force also concluded
that there was a failure of the interconnected grids reliability organizations
(MISO and PJM) to provide effective diagnostic support. The final report is
publicly available through the Department of Energys website (www.doe.gov).
FirstEnergy believes that the final report does not provide a complete and
comprehensive picture of the conditions that contributed to the August 14, 2003
power outages and that it does not adequately address the underlying causes of
the outages. FirstEnergy remains convinced that the outages cannot be explained
by events on any one utilitys system. The final report contains 46
recommendations to prevent or minimize the scope of future blackouts.
Forty-five of those recommendations relate to broad industry or policy matters
while one, including subparts, relates to activities the Task Force recommends
be undertaken by FirstEnergy, MISO, PJM, and ECAR. FirstEnergy implemented
several initiatives, both prior to and since the August 14, 2003 power outages,
which are consistent with these and other recommendations and collectively
enhance the reliability of its electric system. FirstEnergy certified to NERC
on June 30, 2004, completion of various reliability recommendations and further
received independent verification of completion status from a NERC verification 131




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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 September 30, 2004 for any expenditures in excess of
those actually incurred through that date. FirstEnergy is vigorously defending these actions, but cannot predict the
outcome of any of these proceedings or whether any further regulatory
proceedings or legal actions may be instituted against the Companies. In
particular, if FirstEnergy or its subsidiaries were ultimately determined to
have legal liability in connection with these proceedings, it could have a
material adverse effect on FirstEnergys or its subsidiaries financial
condition and results of operations. Reliability Initiatives On October 15, 2003, NERC issued a letter to all NERC control areas and
reliability coordinators requesting a review of various reliability practices.
The Company response confirmed that its review was completed and that various
enhancements were underway to current practices. On February 10, 2004, NERC
issued its Recommended Actions to Prevent and Mitigate the Impacts of Future
Cascading Blackouts, a portion of which were directed at the FirstEnergy
companies and broadly focused on initiatives that were recommended for
completion by June 30, 2004. FirstEnergys detailed implementation plan was
endorsed by the NERC Board of Trustees on May 7, 2004. The various initiatives
recommended by NERC were certified as complete by June 30, 2004, with one minor
exception related to reactive testing of certain generators expected to be
completed later in 2004. On April 5, 2004, the U.S.  Canada Power System Outage Task Force issued
a Final Report on the August 14, 2003 power outages. The Final Report contains
46 recommendations to prevent or minimize the scope of future blackouts.
Forty-five of those recommendations relate to broad industry or policy matters
while one relates to activities the Task Force recommended be undertaken by

FirstEnergy, MISO, PJM and ECAR. FirstEnergy completed the Task Force
activities that were directed toward FirstEnergy and reported completion on
June 30, 2004. With respect to each of the foregoing initiatives, FirstEnergy requested
and NERC provided, a technical assistance team of experts to provide ongoing
guidance and assistance in implementing and confirming timely and successful
completion. NERC further assembled an independent verification team to confirm
implementation of the foregoing initiatives required to be completed as of June
30, 2004. The NERC Verification Team reported, on July 14, 2004, that
FirstEnergy has completed the recommended policies, procedures and actions
required to be completed by June 30, 2004 or summer 2004, with exceptions noted
by FirstEnergy. Implementation of the recommendations has not required
incremental material investment or upgrades to existing equipment. Legal Matters Various lawsuits, claims (including claims for asbestos exposure) and
proceedings related to JCP&Ls normal business operations are pending against
JCP&L, 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. In August 2002, the trial court granted partial summary judgment to JCP&L
and dismissed the plaintiffs claims for consumer fraud, common law fraud,
negligent misrepresentation, and strict products liability. In November 2003,
the trial court granted JCP&Ls motion to decertify the class and denied
plaintiffs motion to permit into evidence their class-wide damage model
indicating damages in excess of $50 million. These class decertification and
damage rulings were appealed to the Appellate Division. The Appellate Court
issued a decision on July 8, 2004, affirming the decertification of the
originally certified class but remanding for certification of a class limited
to those customers directly impacted by the outages of transformers in Red
Bank, New Jersey. On September 8, 2004, the New Jersey Supreme Court denied
the motions filed by plaintiffs and JCP&L for leave to appeal the decision of
the Appellate Court. JCP&L is unable to predict the outcome of these matters
and no liability has been accrued as of September 30, 2004. 132




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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, 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. 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. 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. 133




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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 in the first
nine months 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. In the third quarter of 2004, FirstEnergy made a $500 million voluntary
contribution ($62 million funded by JCP&L) to its pension plan. This
contribution will mitigate future funding requirements and significantly reduce
the year-end minimum pension liability that currently reduces JCP&Ls
accumulated other comprehensive income by $48 million. 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 the carrying value of the goodwill. JCP&Ls most recent annual
review was completed in the third quarter of 2004, 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 nine months 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 September 30, 2004, JCP&L had approximately $2
billion of goodwill. New Accounting Standards And Interpretations EITF Issue No. 03-1, The Meaning of Other-Than-Temporary and Its
Application to Certain Investments In March 2004, the EITF reached a consensus on the application guidance
for Issue 03-1. EITF 03-1 provides a model for determining when investments in
certain debt and equity securities are considered other than temporarily
impaired. When an impairment is other-than-temporary, the investment must be
measured at fair value and the impairment loss recognized in earnings. The
recognition and measurement provisions of EITF 03-1, which were to be 134




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effective for periods beginning after June 15, 2004, were delayed by the
issuance of FSP EITF 03-1-1 in September 2004. 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 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, 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. See Note 2
 Consolidation for a discussion of variable interest entities. 135




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METROPOLITAN EDISON COMPANY 
 CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited) Three Months Ended
    
    Nine Months EndedSeptember 30,
    
    September 30,2004
    
    2003
    
    2004
    
    2003(In thousands)OPERATING REVENUES
    
    $
    285,419
    
    
    $
    261,199
    
    
    $
    788,361
    
    
    $
    730,114OPERATING EXPENSES AND TAXES:Purchased power
    
    
    146,938
    
    
    
    133,471
    
    
    
    421,660
    
    
    
    376,405Other operating costs
    
    
    50,141
    
    
    
    45,875
    
    
    
    130,210
    
    
    
    117,997Provision for depreciation and amortization
    
    
    40,939
    
    
    
    40,042
    
    
    
    109,107
    
    
    
    106,951General taxes
    
    
    18,680
    
    
    
    18,406
    
    
    
    53,103
    
    
    
    50,804Income taxes
    
    
    8,448
    
    
    
    4,153
    
    
    
    17,179
    
    
    
    16,136Total operating expenses and taxes
    
    
    265,146
    
    
    
    241,947
    
    
    
    731,259
    
    
    
    668,293OPERATING INCOME
    
    
    20,273
    
    
    
    19,252
    
    
    
    57,102
    
    
    
    61,821OTHER INCOME
    
    
    6,888
    
    
    
    5,162
    
    
    
    18,530
    
    
    
    15,637NET INTEREST CHARGES:Interest on long-term debt
    
    
    8,823
    
    
    
    8,497
    
    
    
    31,208
    
    
    
    28,378Allowance for borrowed funds used during construction
    
    
    (65
    )
    
    
    (94
    )
    
    
    (208
    )
    
    
    (252
    )Deferred interest
    
    
    
    
    
    
    (192
    )
    
    
    
    
    
    
    (1,187
    )Other interest expense
    
    
    1,326
    
    
    
    2,521
    
    
    
    2,846
    
    
    
    3,386Subsidiarys preferred stock dividend requirements
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    3,779Net interest charges
    
    
    10,084
    
    
    
    10,732
    
    
    
    33,846
    
    
    
    34,104INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING
CHANGE
    
    
    17,077
    
    
    
    13,682
    
    
    
    41,786
    
    
    
    43,354Cumulative effect of accounting change (net of income
taxes of $154,000) (Note 2)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    217NET INCOME
    
    
    17,077
    
    
    
    13,682
    
    
    
    41,786
    
    
    
    43,571OTHER COMPREHENSIVE INCOME (LOSS):Minimum liability for unfunded retirement benefits
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (62,101
    )Unrealized gain (loss) on derivative hedges
    
    
    84
    
    
    
    
    
    
    
    (3,182
    )
    
    
    78Unrealized loss on available for sale securities
    
    
    
    
    
    
    (56
    )
    
    
    (25
    )
    
    
    (12
    )Other comprehensive income (loss)
    
    
    84
    
    
    
    (56
    )
    
    
    (3,207
    )
    
    
    (62,035
    )Income tax related to other comprehensive income
    
    
    1,314
    
    
    
    
    
    
    
    1,314
    
    
    
    25,660Other comprehensive income (loss), net of tax
    
    
    1,398
    
    
    
    (56
    )
    
    
    (1,893
    )
    
    
    (36,375
    )TOTAL COMPREHENSIVE INCOME
    
    $
    18,475
    
    
    $
    13,626
    
    
    $
    39,893
    
    
    $
    7,196
 The preceding Notes to Consolidated Financial Statements as they relate to
Metropolitan Edison Company are an integral part of these statements. 136




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METROPOLITAN EDISON COMPANY 
 CONSOLIDATED BALANCE SHEETS
(Unaudited) September 30,
    
    December 31,2004
    
    2003(In thousands)ASSETSUTILITY PLANT:In service
    
    $
    1,789,673
    
    
    $
    1,838,567Less-Accumulated provision for depreciation
    
    
    704,342
    
    
    
    772,1231,085,331
    
    
    
    1,066,444Construction work in progress
    
    
    15,871
    
    
    
    21,9801,101,202
    
    
    
    1,088,424OTHER PROPERTY AND INVESTMENTS:Nuclear plant decommissioning trusts
    
    
    202,235
    
    
    
    192,409Long-term notes receivable from associated companies
    
    
    10,252
    
    
    
    9,892Other
    
    
    34,199
    
    
    
    34,922246,686
    
    
    
    237,223CURRENT ASSETS:Cash and cash equivalents
    
    
    120
    
    
    
    121Notes receivable from associated companies
    
    
    23,152
    
    
    
    10,467Receivables-Customers (less accumulated provisions of $4,824,000 and $4,943,000,
respectively, for uncollectible accounts)
    
    
    115,115
    
    
    
    118,933Associated companies
    
    
    24,404
    
    
    
    45,934Other (less accumulated provisions of $11,000 and $68,000, respectively,
for uncollectible accounts)
    
    
    18,156
    
    
    
    22,750Prepayments and other
    
    
    21,586
    
    
    
    6,600202,533
    
    
    
    204,805DEFERRED CHARGES:Regulatory assets
    
    
    785,303
    
    
    
    1,028,432Goodwill
    
    
    877,942
    
    
    
    884,279Other
    
    
    24,626
    
    
    
    30,8241,687,871
    
    
    
    1,943,535$
    3,238,292
    
    
    $
    3,473,987CAPITALIZATION AND LIABILITIESCAPITALIZATION:Common stockholders equity Common stock, without par value, authorized 900,000 shares-
859,500 shares outstanding
    
    $
    1,294,257
    
    
    $
    1,298,130Accumulated other comprehensive loss
    
    
    (34,367
    )
    
    
    (32,474
    )Retained earnings
    
    
    33,797
    
    
    
    27,011Total common stockholders equity
    
    
    1,293,687
    
    
    
    1,292,667Long-term debt and other long-term obligations
    
    
    701,863
    
    
    
    636,3011,995,550
    
    
    
    1,928,968CURRENT LIABILITIES:Currently payable long-term debt
    
    
    30,435
    
    
    
    40,469Short-term borrowings-Associated companies
    
    
    
    
    
    
    65,335Other
    
    
    70,000
    
    
    
    Accounts payable-Associated companies
    
    
    39,849
    
    
    
    45,459Other
    
    
    21,632
    
    
    
    33,878Accrued taxes
    
    
    2,506
    
    
    
    8,762Accrued interest
    
    
    11,721
    
    
    
    11,848Other
    
    
    37,854
    
    
    
    22,162213,997
    
    
    
    227,913NONCURRENT LIABILITIES:Accumulated deferred income taxes
    
    
    281,823
    
    
    
    297,140Power purchase contract loss liability
    
    
    430,239
    
    
    
    584,340Asset retirement obligation
    
    
    130,842
    
    
    
    210,178Retirement benefits
    
    
    67,220
    
    
    
    105,552Other
    
    
    118,621
    
    
    
    119,8961,028,745
    
    
    
    1,317,106COMMITMENTS, GUARANTEES AND CONTINGENCIES(Note 3)$
    3,238,292
    
    
    $
    3,473,987
 The preceding Notes to Consolidated Financial Statements as they relate to
Metropolitan Edison Company are an integral part of these balance sheets. 137




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##### Table of Contents



METROPOLITAN EDISON COMPANY 
 CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited) Three Months Ended
    
    Nine Months EndedSeptember 30,
    
    September 30,2004
    
    2003
    
    2004
    
    2003(In thousands)CASH FLOWS FROM OPERATING ACTIVITIES:Net income
    
    $
    17,077
    
    
    $
    13,682
    
    
    $
    41,786
    
    
    $
    43,571Adjustments to reconcile net income to net
cash from operating activities-Provision for depreciation and amortization
    
    
    40,939
    
    
    
    40,042
    
    
    
    109,107
    
    
    
    106,951Deferred costs, net
    
    
    (15,629
    )
    
    
    (15,913
    )
    
    
    (45,616
    )
    
    
    (47,063
    )Deferred income taxes, net
    
    
    871
    
    
    
    (315
    )
    
    
    (4,236
    )
    
    
    9,349Amortization of investment tax credits
    
    
    (205
    )
    
    
    (205
    )
    
    
    (617
    )
    
    
    (615
    )Accrued retirement benefit obligation
    
    
    (273
    )
    
    
    3,620
    
    
    
    492
    
    
    
    7,144Accrued compensation, net
    
    
    649
    
    
    
    (120
    )
    
    
    201
    
    
    
    6,207Cumulative effect of accounting change (Note 2)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (371
    )Pension trust contribution
    
    
    (38,823
    )
    
    
    
    
    
    
    (38,823
    )
    
    
    Receivables
    
    
    (2,599
    )
    
    
    11,953
    
    
    
    29,943
    
    
    
    2,007Materials and supplies
    
    
    5
    
    
    
    (6
    )
    
    
    41
    
    
    
    (145
    )Prepayments and other current assets
    
    
    14,298
    
    
    
    16,136
    
    
    
    (15,027
    )
    
    
    (2,500
    )Accounts payable
    
    
    (12,536
    )
    
    
    (89,944
    )
    
    
    (17,857
    )
    
    
    (5,647
    )Accrued taxes
    
    
    (145
    )
    
    
    214
    
    
    
    (6,255
    )
    
    
    (12,460
    )Accrued interest
    
    
    (3,006
    )
    
    
    (4,161
    )
    
    
    (127
    )
    
    
    (7,951
    )Other
    
    
    (7,356
    )
    
    
    (11,300
    )
    
    
    (9,581
    )
    
    
    (30,201
    )Net cash provided from (used for) operating activities
    
    
    (6,733
    )
    
    
    (36,317
    )
    
    
    43,431
    
    
    
    68,276CASH FLOWS FROM FINANCING ACTIVITIES:New Financing-Long-term debt
    
    
    
    
    
    
    
    
    
    
    247,607
    
    
    
    247,696Short-term borrowings, net
    
    
    70,000
    
    
    
    35,591
    
    
    
    4,665
    
    
    
    Redemptions and Repayments-Long-term debt
    
    
    (45,936
    )
    
    
    (32
    )
    
    
    (196,371
    )
    
    
    (230,467
    )Short-term borrowings, net
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (32,043
    )Dividend Payments-Common stock
    
    
    (10,000
    )
    
    
    (7,000
    )
    
    
    (35,000
    )
    
    
    (27,000
    )Net cash provided from (used for) financing activities
    
    
    14,064
    
    
    
    28,559
    
    
    
    20,901
    
    
    
    (41,814
    )CASH FLOWS FROM INVESTING ACTIVITIES:Property additions
    
    
    (12,390
    )
    
    
    (8,382
    )
    
    
    (33,733
    )
    
    
    (28,284
    )Contributions to nuclear decommissioning trusts
    
    
    (2,371
    )
    
    
    (2,371
    )
    
    
    (7,113
    )
    
    
    (7,112
    )Loan repayment from (loans to) associated companies, net
    
    
    17,989
    
    
    
    17,144
    
    
    
    (13,046
    )
    
    
    (7,566
    )Other
    
    
    (10,559
    )
    
    
    1,179
    
    
    
    (10,441
    )
    
    
    957Net cash provided from (used for) investing activities
    
    
    (7,331
    )
    
    
    7,570
    
    
    
    (64,333
    )
    
    
    (42,005
    )Net decrease in cash and cash equivalents
    
    
    
    
    
    
    (188
    )
    
    
    (1
    )
    
    
    (15,543
    )Cash and cash equivalents at beginning of period
    
    
    120
    
    
    
    330
    
    
    
    121
    
    
    
    15,685Cash and cash equivalents at end of period
    
    $
    120
    
    
    $
    142
    
    
    $
    120
    
    
    $
    142
 The preceding Notes to Consolidated Financial Statements as they relate to
Metropolitan Edison Company are an integral part of these statements. 138




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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 September 30, 2004, and the related
consolidated statements of income and comprehensive income and cash flows for
each of the three-month and nine-month periods ended September 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
November 2, 2004 139




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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 conducts business in eastern Pennsylvania, providing regulated
transmission and distribution services. Met-Ed also provides generation
services to those customers electing to retain Met-Ed as their power supplier.
Met-Ed has unbundled the price for electricity into its component elements 
including generation, transmission, distribution and transition charges. Results of Operations Net income in the third quarter of 2004 increased to $17 million from $14
million in the third quarter of 2003. The increase in net income resulted
principally from higher operating revenues and lower interest charges partially
offset by higher purchased power and other operating costs. For the first nine
months of 2004, net income decreased to $42 million compared to $44 million in
the same period of 2003. The decrease in net income resulted from higher
purchased power, depreciation and amortization, and other operating costs
partially offset by higher operating revenues. 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 9.3% in the third quarter
of 2004 compared with the same period of 2003, principally due to higher
revenues from distribution deliveries ($8 million), retail generation ($6
million) and an $8 million increase in transmission revenues. Higher retail
generation sales revenues reflected a 10.9% increase in generation sales
primarily due to commercial and industrial generation customers returning to
Met-Ed from alternative suppliers. The increase in commercial and industrial
sales was partially offset by lower retail generation unit prices in all
customer classes. Higher revenues from distribution throughput were due to a
2.8% increase in distribution deliveries and higher unit prices. An improving
economy in Met-Eds franchise area resulted in increased distribution
deliveries to commercial and industrial customers. The higher distribution unit
prices are due to the PPUC Restructuring Settlement order (see Regulatory
Matters) with a corresponding decrease in retail generation unit prices. Operating revenues increased by $58 million or 8.0% in the first nine
months of 2004 compared with the same period in 2003, primarily due to
increases of $29 million and $18 million in distribution and retail generation
sales revenues, respectively, and higher transmission revenues. Sales of
electric generation by alternative suppliers as a percent of total sales
delivered to commercial and industrial customers in Met-Eds franchise area
decreased by 3.2 and 19.4 percentage points, respectively. The decrease in
customers shopping resulted in an 11.3% increase in retail generation sales
which was partially offset by the lower generation unit prices discussed above.
Higher revenues from electricity throughput resulted primarily from higher unit
prices, an increase in the retail customer base and an improving economy,
partially offset by cooler weather in the summer months of 2004. The significant decrease in customer shopping over the past year reflects
Met-Eds low generation price as the provider of last resort. Alternative
suppliers have not been able to match that price (shopping credit) by a
sufficient margin in order to ensure profitability, particularly to the
industrial sector. Changes in distribution deliveries in the third quarter and first nine
months of 2004 from the same periods of 2003 are summarized in the following
table: Changes in KWH Deliveries
    
    Three Months
    
    Nine MonthsIncrease (Decrease)Distribution Deliveries:Residential
    
    
    0.4
    %
    
    
    2.3
    %Commercial
    
    
    6.3
    %
    
    
    5.4
    %Industrial
    
    
    2.3
    %
    
    
    0.2
    %Total Distribution Deliveries
    
    
    2.8
    %
    
    
    2.6
    %
 Operating Expenses and Taxes Total operating expenses and taxes increased $23 million in the third
quarter and $63 million in the first nine months of 2004 compared to the same
periods of 2003. The following table presents changes from the prior year by
expense category. 140




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##### Table of Contents



Operating Expenses and Taxes  Changes
    
    Three Months
    
    Nine MonthsIncrease (Decrease)
    
    (In millions)Purchased power costs
    
    $
    14
    
    
    $
    46Other operating costs
    
    
    4
    
    
    
    12Total operation and maintenance expenses
    
    
    18
    
    
    
    58Provision for depreciation and amortization
    
    
    1
    
    
    
    2General taxes
    
    
    
    
    
    
    2Income taxes
    
    
    4
    
    
    
    1Total operating expenses and taxes
    
    $
    23
    
    
    $
    63
 Higher purchased power costs in the third quarter and first nine months of
2004, compared to the same periods of 2003, were due to increased PLR
kilowatt-hour purchases from FES. Other operating costs increased by $4
million in the third quarter of 2004 primarily due to higher transmission
costs, which were assumed by Met-Ed earlier in the year due to a change in the
power supply agreement with FES. Other operating costs increased by $12 million
in the first nine months of 2004 due to higher vegetation management and
transmission costs, partially offset by lower costs associated with storm
restoration activities in 2004. Depreciation and amortization expenses were $2
million higher in the first nine months of 2004 due to increased amortization
of regulatory assets being recovered through the CTC rate. 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 decreased by $0.6 million in the third quarter and
$0.3 million in the first nine months of 2004 compared to the same periods in
2003 primarily due to the redemption of subordinated debentures related to the
7.35% trust preferred securities in June 2004 and the redemption of $50 million
of long-term debt in the first quarter of 2004. The decrease in net interest
charges from these redemptions was partially offset by the issuance of $250
million of senior notes at the end of the first quarter of 2004 and the
elimination of deferred interest for PLR energy costs in the third quarter of
2003. Capital Resources and Liquidity Met-Eds cash requirements in 2004 for operating expenses, construction
expenditures, scheduled debt maturities and optional debt redemptions are
expected to be met without materially 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 September 30, 2004, Met-Ed had $120,000 of cash and cash equivalents
compared with $121,000 as of December 31, 2003. The major sources of changes in
these balances are summarized below. Cash Flows From Operating Activities Cash provided from (used for) operating activities during the third
quarter and first nine months of 2004, compared with the corresponding periods
of 2003, were as follows: Three Months Ended
    
    Nine Months EndedSeptember 30,
    
    September 30,Operating Cash Flows
    
    2004
    
    2003
    
    2004
    
    2003(In millions)Cash earnings(1)
    
    $
    43
    
    
    $
    41
    
    
    $
    101
    
    
    $
    125Pension trust contribution
    
    
    (39
    )
    
    
    
    
    
    
    (39
    )
    
    
    Working capital and other
    
    
    (11
    )
    
    
    (77
    )
    
    
    (19
    )
    
    
    (57
    )Total
    
    $
    (7
    )
    
    $
    (36
    )
    
    $
    43
    
    
    $
    68
  (1) Includes net income,
depreciation and amortization, deferred
costs recoverable as regulatory assets,
deferred income taxes, investment tax
credits and major noncash credits. 141




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Net cash used for operating activities increased $29 million in the third
quarter of 2004 from the third quarter of 2003 due to a $66 million increase
from changes in working capital and a $2 million increase in cash earnings as
described above under Results of Operations, offset by a $39 million
voluntary pension trust contribution. The largest factors contributing to the
increase in working capital was a $77 million increase in accounts payable
partially offset by a $14 million increase in accounts receivable. Net cash provided from operating activities decreased $25 million in the
first nine months of 2004 from the same period of 2003 as a result of the $39
million pension trust contribution, a $24 million decrease in cash earnings,
partially offset by a $38 million increase in working capital. Working capital
increased primarily due to a $28 million decrease in accounts receivable and a
change in accrued taxes, accrued interest and other current liabilities
aggregating $27 million. Partially offsetting the increase in working capital
was a decrease of $12 million in accounts payable and an increase in
prepayments and other current assets of $13 million. Cash Flows From Financing Activities In the third quarter of 2004, net cash provided from financing activities
decreased to $14 million compared with $29 million in the third quarter of 2003
due to a $46 million increase in debt redemptions and a $3 million increase in
common stock dividends, partially offset by a $34 million increase in short
term borrowings. In the first nine months of 2004 net cash provided from
financing activities was $21 million compared to $42 million of net cash used
for financing activities in the first nine months of 2003. The change reflected
a $34 million decrease in debt redemptions and a $37 million increase in
short-term borrowings, partially offset by an $8 million increase in common
stock dividends to FirstEnergy. In March 2004, Met-Ed completed a receivables financing arrangement that
provides 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 drawn in the third quarter
of 2004 for $70 million and matures on March 29, 2005. As of September 30, 2004, Met-Ed had approximately $23 million of cash and
temporary investments (which include short-term notes receivable from
associated companies) and $70 million of short-term indebtedness. Met-Ed has
obtained authorization from the SEC to incur short-term debt of up to $250
million (including the utility money pool). Under the terms of its senior note
indenture, Met-Ed is no longer permitted to issue FMB so long as senior notes
are outstanding. Met-Ed 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
third quarter of 2004 was 1.28%. Met-Eds access to capital markets and costs of financing are dependent on
the ratings of its securities and that of FirstEnergy. On August 26, 2004, S&P
lowered its rating on certain Met-Ed Senior Notes to BBB- from BBB. The
rationale for the ratings change was that Met-Eds senior secured notes, in
aggregate, now comprise greater than 80% of Met-Eds total debt outstanding.
According to the terms of the senior note indenture, once the 80% threshold is
reached, the collateral mortgage bond security falls away and all senior
secured notes that were secured by Met-Eds senior note indenture become
unsecured. The one notch lower rating reflects this loss of collateral
security. The BBB senior secured rating on Met-Eds first mortgage bonds
remained unchanged. Also on August 26, 2004, S&P stated that a favorable outcome of
FirstEnergys Ohio Rate Stabilization Plan auction process and a favorable
resolution of pending environmental litigation would support a higher ratings
outlook, or possibly a higher rating. S&P noted that a ratings upgrade in 2004
does not appear likely because those major issues would most likely not be
resolved before the end of 2004. On September 14, 2004, S&P stated that
FirstEnergys $500 million voluntary contribution to its pension plan was
credit neutral. Cash Flows From Investing Activities In the third quarter of 2004, net cash used for investing activities
totaled $7 million, compared to net cash provided from investing activities of
$8 million in the third quarter of 2003. A $4 million increase in property
additions and a $9 million capital transfer from FESC contributed to the
increase in cash used in investing activities. In the first nine months of
2004, net cash used in investing activities totaled $64 million, compared to
$42 million for the same period of 2003. A $5 million increase in loans to
associated companies, and a $17 million increase in property additions and the
capital transfer from FESC in the third quarter contributed to the increase. 142




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During the fourth quarter of 2004, capital requirements for property
additions are expected to be about $19 million. Those 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 third quarter and first nine months of 2004 is summarized in the
following table: Increase (Decrease) in the Fair Value
    
    Three Months Ended
    
    Nine Months Endedof Commodity Derivative Contracts
    
    September 30, 2004
    
    September 30, 2004Non-Hedge
    
    Hedge
    
    Total
    
    Non-Hedge
    
    Hedge
    
    Total(In millions)Change in the Fair Value of Commodity Derivative ContractsOutstanding net asset at beginning of period
    
    $
    30
    
    
    $
    
    
    
    $
    30
    
    
    $
    31
    
    
    $
    
    
    
    $
    31New contract value when entered
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Additions/Change in value of existing contracts
    
    
    1
    
    
    
    
    
    
    
    1
    
    
    
    
    
    
    
    
    
    
    
    Change in techniques/assumptions
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    

    Settled contracts
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Net Assets - Derivative Contracts as of September 30, 2004(1)
    
    $
    31
    
    
    $
    
    
    
    $
    31
    
    
    $
    31
    
    
    $
    
    
    
    $
    31Impact of Changes in Commodity Derivative Contracts(2)Income Statement Effects (Pre-Tax)
    
    $
    1
    
    
    $
    
    
    
    $
    1
    
    
    $
    1
    
    
    $
    
    
    
    $
    1Balance Sheet Effects:Other Comprehensive Income (Pre-Tax)
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    Regulatory Liability
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    (1
    )
    
    $
    
    
    
    $
    (1
    )
  (1) Includes $31 million in non-hedge commodity derivative contracts which
are offset by a regulatory liability.(2) Represents the increase in value of existing contracts, settled contracts
and changes in techniques/assumptions. Derivatives included on the Consolidated Balance Sheet as of September 30,
2004: Non-Hedge
    
    Hedge
    
    Total(In millions)Current-Other Assets
    
    $
    
    
    
    $
    
    
    
    $
    Other Liabilities
    
    
    
    
    
    
    
    
    
    
    Non-Current-Other Deferred Charges
    
    
    31
    
    
    
    
    
    
    
    31Other Liabilities
    
    
    
    
    
    
    
    
    
    
    Net assets
    
    $
    31
    
    
    $
    
    
    
    $
    31
 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: 143




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##### Table of Contents



Source of Information Fair Value by Contract Year
    
    2004(1)
    
    2005
    
    2006
    
    2007
    
    Thereafter
    
    Total(In millions)Prices based on external sources(2)
    
    $
    4
    
    
    $
    5
    
    
    $
    5
    
    
    $
    
    
    
    $
    
    
    
    $
    14Prices based on models
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    5
    
    
    
    12
    
    
    
    17Total(3)
    
    $
    4
    
    
    $
    5
    
    
    $
    5
    
    
    $
    5
    
    
    $
    12
    
    
    $
    31
  (1) For the last quarter of 2004.(2) Broker quote sheets.(3) Includes $31 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 September 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 September 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 September 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 transmission and distribution systems, which
remain 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 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. 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 144




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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 $785 million and $1.03
billion as of September 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 are 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 $28,000 as of September 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. Power Outages and Related Litigation On August 14, 2003, various states and parts of southern Canada
experienced widespread power outages. The outages affected approximately 1.4
million customers in FirstEnergys service area. On April 5, 2004, the U.S.
Canada Power System Outage Task Force released its final report on the
outages. In the final report, the Task Force concluded, among other things,
that the problems leading to the outages began in FirstEnergys Ohio service
area. Specifically, the final report concludes, among other things, that the
initiation of the August 14, 2003 power outages resulted from an alleged
failure of both FirstEnergy and ECAR to assess and understand perceived
inadequacies within the FirstEnergy system; inadequate situational awareness of
the developing conditions; and a perceived failure to adequately manage tree
growth in certain transmission rights of way. The Task Force also concluded
that there was a failure of the interconnected grids reliability organizations
(MISO and PJM) to provide effective diagnostic support. The final report is
publicly available through the Department of Energys website (www.doe.gov).
FirstEnergy believes that the final report does not provide a complete and
comprehensive picture of the conditions that contributed to the August 14, 2003
power outages and that it does not adequately address the underlying causes of
the outages. FirstEnergy remains convinced that the outages cannot be explained
by events on any one utilitys system. The final report contains 46
recommendations to prevent or minimize the scope of future blackouts.
Forty-five of those recommendations relate to broad industry or policy matters
while one, including subparts, relates to activities the Task Force recommends
be undertaken by FirstEnergy, MISO, PJM, and ECAR. FirstEnergy implemented
several initiatives, both prior to and since the August 14, 2003 power outages,
which are consistent with these and other recommendations and collectively
enhance the reliability of its electric system. FirstEnergy certified to NERC
on June 30, 2004, completion of various reliability recommendations and further
received independent verification of completion status from a NERC verification
team on July 14, 2004 (see Reliability Initiatives below). FirstEnergys
implementation of these recommendations 145




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included completion of the Task Force recommendations that were directed toward
FirstEnergy. As many of these initiatives already were in process and budgeted
in 2004, FirstEnergy does not believe that any incremental expenses associated
with additional initiatives undertaken during 2004 will have a material effect
on its operations or financial results. FirstEnergy notes, however, that the
applicable government agencies and reliability coordinators may take a
different view as to recommended enhancements or may recommend additional
enhancements in the future that could require additional, material
expenditures. FirstEnergy has not accrued a liability as of September 30, 2004
for any expenditures in excess of those actually incurred through that date. FirstEnergy is vigorously defending these actions, but cannot predict the
outcome of any of these proceedings or whether any further regulatory
proceedings or legal actions may be instituted against the Companies. In
particular, if FirstEnergy or its subsidiaries were ultimately determined to
have legal liability in connection with these proceedings, it could have a
material adverse effect on FirstEnergys or its subsidiaries financial
condition and results of operations. Reliability Initiatives On October 15, 2003, NERC issued a letter to all NERC control areas and
reliability coordinators requesting a review of various reliability practices.
FirstEnergys response confirmed that its review was completed and that various
enhancements were underway to current practices. On February 10, 2004, NERC
issued its Recommended Actions to Prevent and Mitigate the Impacts of Future
Cascading Blackouts, a portion of which were directed at the FirstEnergy
companies and broadly focused on initiatives that were recommended for
completion by June 30, 2004. FirstEnergys detailed implementation plan was
endorsed by the NERC Board of Trustees on May 7, 2004. The various initiatives
recommended by NERC were certified as complete by June 30, 2004, with one minor
exception related to reactive testing of certain generators expected to be
completed later this year. On April 5, 2004, the U.S.  Canada Power System Outage Task Force issued
a Final Report on the August 14, 2003 power outages. The Final Report contains
46 recommendations to prevent or minimize the scope of future blackouts.
Forty-five of those recommendations relate to broad industry or policy matters
while one relates to activities the Task Force recommended be undertaken by
FirstEnergy, MISO, PJM and ECAR. FirstEnergy completed the Task Force
activities that were directed toward FirstEnergy and reported completion on
June 30, 2004. With respect to each of the foregoing initiatives, FirstEnergy requested
and NERC provided, a technical assistance team of experts to provide ongoing
guidance and assistance in implementing and confirming timely and successful
completion. NERC further assembled an independent verification team to confirm
implementation of the foregoing initiatives required to be completed as of June
30, 2004. The NERC Verification Team reported, on July 14, 2004, that
FirstEnergy has completed the recommended policies, procedures, and actions
required to be completed by June 30, 2004 or summer 2004, with exceptions noted
by FirstEnergy. Implementation of the recommendations has not required
incremental material investment or upgrades to existing equipment. 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. Hearings were held in early August 2004. On September 30, 2004,
Met-Ed filed a settlement agreement with the PPUC that addresses the issues
related to this investigation. As part of the settlement, Met-Ed agreed to
enhance service reliability, performance reporting and communications with
customers and together with Penn and Penelec, to collectively maintain their
current spending levels of at least $255 million annually on combined capital

and operation and maintenance expenditures for transmission and distribution
for the years 2005 through 2007. In November 2004, the PPUC accepted the
recommendation of the ALJ approving the settlement. 146




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Legal Matters Various lawsuits, claims (including claims for asbestos exposure) and
proceedings related to Met-Eds 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 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 postretirement 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 147




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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 in the first
nine months 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. In the third quarter of 2004, FirstEnergy made a $500 million voluntary
contribution ($39 million funded by Met-Ed) to its pension plan. This
contribution will mitigate future funding requirements and significantly reduce
the year-end minimum pension liability that currently reduces Met-Eds
accumulated other comprehensive income by $33 million. 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
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 2004, 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 nine months of 2004, Met-Ed reduced
goodwill by $6 million for pre-merger interest received on an income tax refund
and other tax benefits. As of September 30, 2004, Met-Ed had $878 million of
goodwill. 148




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New Accounting Standards And Interpretations EITF Issue No. 03-1, The Meaning of Other-Than-Temporary and Its
Application to Certain Investments In March 2004, the EITF reached a consensus on the application guidance
for Issue 03-1. EITF 03-1 provides a model for determining when investments in
certain debt and equity securities are considered other than temporarily
impaired. When an impairment is other-than-temporary, the investment must be
measured at fair value and the impairment loss recognized in earnings. The
recognition and measurement provisions of EITF 03-1, which were to be effective
for periods beginning after June 15, 2004, were delayed by the issuance of FSP
EITF 03-1-1 in September 2004. 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 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, 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. See Note
2  Consolidation for a discussion of variable interest entities. 149




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PENNSYLVANIA ELECTRIC COMPANY 
 CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited) Three Months Ended
    
    Nine Months EndedSeptember 30,
    
    September 30,2004
    
    2003
    
    2004
    
    2003Restated
    
    
    
    
    
    Restated(See Note 2)
    
    
    
    
    
    (See Note 2)(In thousands)OPERATING REVENUES
    
    $
    254,339
    
    
    $
    242,146
    
    
    $
    752,986
    
    
    $
    728,948OPERATING EXPENSES AND TAXES:Purchased power
    
    
    137,146
    
    
    
    137,418
    
    
    
    432,974
    
    
    
    420,104Other operating costs
    
    
    37,100
    
    
    
    48,881
    
    
    
    122,988
    
    
    
    132,796Provision for depreciation and amortization
    
    
    24,040
    
    
    
    23,453
    
    
    
    74,359
    
    
    
    74,347General taxes
    
    
    16,913
    
    
    
    17,032
    
    
    
    50,795
    
    
    
    48,630Income taxes
    
    
    11,693
    
    
    
    1,692
    
    
    
    16,000
    
    
    
    10,434Total operating expenses and taxes
    
    
    226,892
    
    
    
    228,476
    
    
    
    697,116
    
    
    
    686,311OPERATING INCOME
    
    
    27,447
    
    
    
    13,670
    
    
    
    55,870
    
    
    
    42,637OTHER INCOME
    
    
    1,300
    
    
    
    522
    
    
    
    1,663
    
    
    
    864NET INTEREST CHARGES:Interest on long-term debt
    
    
    7,513
    
    
    
    7,432
    
    
    
    22,528
    
    
    
    22,123Allowance for borrowed funds used during construction
    
    
    (60
    )
    
    
    (77
    )
    
    
    (192
    )
    
    
    (257
    )Deferred interest
    
    
    
    
    
    
    (380
    )
    
    
    190
    
    
    
    (2,525
    )Other interest expense
    
    
    3,058
    
    
    
    2,071
    
    
    
    8,063
    
    
    
    2,333Subsidiarys preferred stock dividend requirements
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    3,777Net interest charges
    
    
    10,511
    
    
    
    9,046
    
    
    
    30,589
    
    
    
    25,451INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING
CHANGE
    
    
    18,236
    
    
    
    5,146
    
    
    
    26,944
    
    
    
    18,050Cumulative effect of accounting change (net of income taxes
of $777,000) (Note 2)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,096NET INCOME
    
    
    18,236
    
    
    
    5,146
    
    
    
    26,944
    
    
    
    19,146OTHER COMPREHENSIVE INCOME (LOSS):Minimum liability for unfunded retirement benefits
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (91,820
    )Unrealized gain (loss) on derivative hedges
    
    
    16
    
    
    
    
    
    
    
    (618
    )
    
    
    72Unrealized gain (loss) on available for sale securities
    
    
    8
    
    
    
    (20
    )
    
    
    (1
    )
    
    
    (4
    )Other comprehensive income (loss)
    
    
    24
    
    
    
    (20
    )
    
    
    (619
    )
    
    
    (91,752
    )Income tax related to other comprehensive income
    
    
    256
    
    
    
    
    
    
    
    256
    
    
    
    37,940Other comprehensive income (loss), net of tax
    
    
    280
    
    
    
    (20
    )
    
    
    (363
    )
    
    
    (53,812
    )TOTAL COMPREHENSIVE INCOME (LOSS)
    
    $
    18,516
    
    
    $
    5,126
    
    
    $
    26,581
    
    
    $
    (34,666
    )
 The preceding Notes to Consolidated Financial Statements as they relate to
Pennsylvania Electric Company are an integral part of these statements. 150




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PENNSYLVANIA ELECTRIC COMPANY 
 CONSOLIDATED BALANCE SHEETS(Unaudited) September 30,
    
    December 31,2004
    
    2003(In thousands)ASSETSUTILITY PLANT:In service
    
    $
    1,963,639
    
    
    $
    1,966,624Less-Accumulated provision for depreciation
    
    
    768,091
    
    
    
    785,7151,195,548
    
    
    
    1,180,909Construction work in progress
    
    
    23,626
    
    
    
    29,0631,219,174
    
    
    
    1,209,972OTHER PROPERTY AND INVESTMENTS:Nuclear plant decommissioning trusts
    
    
    103,910
    
    
    
    102,673Non-utility generation trusts
    
    
    95,721
    
    
    
    43,864Long-term notes receivable from associated companies
    
    
    13,561
    
    
    
    13,794Other
    
    
    18,993
    
    
    
    19,635232,185
    
    
    
    179,966CURRENT ASSETS:Cash and cash equivalents
    
    
    36
    
    
    
    36Receivables-Customers (less accumulated provisions of $5,137,000 and $5,833,000,
respectively, for uncollectible accounts)
    
    
    117,755
    
    
    
    124,462Associated companies
    
    
    58,285
    
    
    
    88,598Other (less accumulated provisions of $60,000 and $399,000, respectively,
for uncollectible accounts)
    
    
    16,981
    
    
    
    15,767Prepayments and other
    
    
    31,133
    
    
    
    2,511224,190
    
    
    
    231,374DEFERRED CHARGES:Regulatory assets
    
    
    294,257
    
    
    
    497,219Goodwill
    
    
    883,513
    
    
    
    898,547Other
    
    
    13,217
    
    
    
    35,1651,190,987
    
    
    
    1,430,931$
    2,866,536
    
    
    $
    3,052,243CAPITALIZATION AND LIABILITIESCAPITALIZATION:Common stockholders equity-Common stock, par value $20 per share, authorized 5,400,000 shares,
5,290,596 shares outstanding
    
    $
    105,812
    
    
    $
    105,812Other paid-in capital
    
    
    1,211,069
    
    
    
    1,215,667Accumulated other comprehensive loss
    
    
    (42,548
    )
    
    
    (42,185
    )Retained earnings
    
    
    36,982
    
    
    
    18,038Total common stockholders equity
    
    
    1,311,315
    
    
    
    1,297,332Long-term debt and other long-term obligations
    
    
    481,961
    
    
    
    438,7641,793,276
    
    
    
    1,736,096CURRENT LIABILITIES:Currently payable long-term debt
    
    
    8,261
    
    
    
    125,762Short-term borrowings-Associated companies
    
    
    189,428
    
    
    
    78,510Other
    
    
    55,000
    
    
    
    Accounts payable-Associated companies
    
    
    37,341
    
    
    
    55,831Other
    
    
    20,667
    
    
    
    40,192Accrued taxes
    
    
    1,132
    
    
    
    8,705Accrued interest
    
    
    15,550
    
    
    
    12,694Other
    
    
    39,679
    
    
    
    21,764367,058
    
    
    
    343,458NONCURRENT LIABILITIES:Asset retirement obligation
    
    
    65,421
    
    
    
    105,089Power purchase contract loss liability
    
    
    482,235
    
    
    
    670,482Retirement benefits
    
    
    99,604
    
    
    
    145,081Other
    
    
    58,942
    
    
    
    52,037706,202
    
    
    
    972,689COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 3)$
    2,866,536
    
    
    $
    3,052,243
 The preceding Notes to Consolidated Financial Statements as they relate to the
Pennsylvania Electric Company are an integral part of these balance sheets. 151




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PENNSYLVANIA ELECTRIC COMPANY 
 CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited) Three Months Ended
    
    Nine Months EndedSeptember 30,
    
    September 30,2004
    
    2003
    
    2004
    
    2003Restated
    
    
    
    
    
    Restated(See Note 2)
    
    
    
    
    
    (See Note 2)(In thousands)CASH FLOWS FROM OPERATING ACTIVITIES:Net income
    
    $
    18,236
    
    
    $
    5,146
    
    
    $
    26,944
    
    
    $
    19,146Adjustments to reconcile net income to net
cash from operating activities-Provision for depreciation and amortization
    
    
    24,040
    
    
    
    23,453
    
    
    
    74,359
    
    
    
    74,347Deferred costs recoverable as regulatory assets
    
    
    (25,618
    )
    
    
    (16,738
    )
    
    
    (62,122
    )
    
    
    (52,135
    )Deferred income taxes, net
    
    
    28,819
    
    
    
    6,356
    
    
    
    31,044
    
    
    
    (31,153
    )Investment tax credits, net
    
    
    (245
    )
    
    
    (247
    )
    
    
    (736
    )
    
    
    (741
    )Accrued retirement benefit obligations
    
    
    1,164
    
    
    
    6,867
    
    
    
    4,805
    
    
    
    18,831Accrued compensation, net
    
    
    894
    
    
    
    (234
    )
    
    
    2,271
    
    
    
    8,618Cumulative effect of accounting change (Note 2)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (1,873
    )Pension trust contribution
    
    
    (50,281
    )
    
    
    
    
    
    
    (50,281
    )
    
    
    Receivables
    
    
    (17,689
    )
    
    
    1,283
    
    
    
    35,806
    
    
    
    10,075Prepayments and other current assets
    
    
    9,703
    
    
    
    (3,923
    )
    
    
    (25,247
    )
    
    
    (9,736
    )Accounts payable
    
    
    (23,255
    )
    
    
    (93,818
    )
    
    
    (38,015
    )
    
    
    (71,846
    )Accrued taxes
    
    
    2
    
    
    
    503
    
    
    
    (7,572
    )
    
    
    383Accrued interest
    
    
    5,605
    
    
    
    5,450
    
    
    
    2,856
    
    
    
    5,564Other
    
    
    562
    
    
    
    (13,005
    )
    
    
    24,851
    
    
    
    (4,177
    )Net cash provided from (used for) operating activities
    
    
    (28,063
    )
    
    
    (78,907
    )
    
    
    18,963
    
    
    
    (34,697
    )CASH FLOWS FROM FINANCING ACTIVITIES:New Financing-Long-term debt
    
    
    
    
    
    
    
    
    
    
    150,000
    
    
    
    Short-term borrowings, net
    
    
    158,282
    
    
    
    38,150
    
    
    
    165,918
    
    
    
    Redemptions and Repayments-Long-term debt
    
    
    (103,241
    )
    
    
    (165
    )
    
    
    (228,453
    )
    
    
    (454
    )Short-term borrowings, net
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (24,708
    )Dividend Payments-Common stock
    
    
    (3,000
    )
    
    
    (10,000
    )
    
    
    (8,000
    )
    
    
    (26,000
    )Net cash provided from (used for) financing activities
    
    
    52,041
    
    
    
    27,985
    
    
    
    79,465
    
    
    
    (51,162
    )CASH FLOWS FROM INVESTING ACTIVITIES:Property additions
    
    
    (10,192
    )
    
    
    (12,347
    )
    
    
    (33,428
    )
    
    
    (31,818
    )Nonutility generation trust withdrawals (contributions)
    
    
    
    
    
    
    
    
    
    
    (50,614
    )
    
    
    106,327Loan repayments from (loans to) associated companies, net
    
    
    (3,124
    )
    
    
    62,597
    
    
    
    (3,144
    )
    
    
    610Other, net
    
    
    (10,662
    )
    
    
    390
    
    
    
    (11,242
    )
    
    
    514Net cash provided from (used for) investing activities
    
    
    (23,978
    )
    
    
    50,640
    
    
    
    (98,428
    )
    
    
    75,633Net change in cash and cash equivalents
    
    
    
    
    
    
    (282
    )
    
    
    
    
    
    
    (10,226
    )Cash and cash equivalents at beginning of period
    
    
    36
    
    
    
    366
    
    
    
    36
    
    
    
    10,310Cash and cash equivalents at end of period
    
    $
    36
    
    
    $
    84
    
    
    $
    36
    
    
    $
    84
 The preceding Notes to Consolidated Financial Statements as they relate to
Pennsylvania Electric Company are an integral part of these statements. 152




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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 September 30, 2004, and the related
consolidated statements of income and comprehensive income and cash flows for
each of the three-month and nine-month periods ended September 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 nine-month periods ended September 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
November 2, 2004 153




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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 conducts business in northern, western and south central Pennsylvania,
providing regulated transmission and distribution services. Penelec also
provides generation services to those customers electing to retain Penelec as
their power supplier. Penelec has unbundled the price for electricity into its
component elements  including generation, transmission, distribution and
transition charges. Restatements of Previously Reported Quarterly Results As discussed in Note 2 to the Consolidated Financial Statements, Penelecs
quarterly results for the third quarter and first nine months 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 $2.0 million ($1.2 million after-tax) and $2.7
million ($1.6 million after-tax) in the third quarter of 2003 and first nine
months of 2003, respectively. 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 third quarter of 2004 increased to $18 million from $5
million in the third quarter of 2003. For the first nine months of 2004, net
income increased to $27 million compared to $19 million in the same period of
2003. Net income in the first nine months of 2003 included an after-tax credit
of $1 million from the cumulative effect of an accounting change due to the
adoption of SFAS 143. Income before the cumulative effect was $18 million in
the first nine months of 2003. Increased results in both 2004 periods resulted
principally from higher operating revenues and lower other operating costs
partially offset by higher net interest charges in both periods and increased
purchased power costs in the first nine months of 2004. Operating revenues increased by $12 million or 5.0% in the third quarter
of 2004 compared with the same period of 2003, primarily due to higher revenues
from distribution deliveries and wholesale sales ($1 million)  partially
offset by lower retail generation revenues. Revenues from distribution
deliveries increased by $10 million resulting from higher unit prices and a
3.5% increase in electricity throughput. Distribution deliveries increased to
commercial and industrial customers reflecting an improving economy in
Penelecs service area. A $2 million decrease in retail generation revenues was
due to lower unit prices which were partially offset by a 3.8% increase in
retail generation kilowatt-hour sales due to generation customers returning
from alternative suppliers. The lower retail generation unit prices are due to
the PPUC Restructuring Settlement order (see Regulatory Matters). For the first nine months of 2004, operating revenues increased $24
million or 3.3% compared to the same period in 2003, reflecting a 3.3% increase
in distribution deliveries that produced a $30 million increase in revenues.
The impact of a 4.4% increase in retail generation sales was more than offset
by lower unit prices that reduced revenues by $6 million. The increase in
retail generation sales reflected the economic factors discussed above and the
decrease in customer shopping. The significant decrease in customer shopping over the past year reflects
Penelecs low generation price as the provider of last resort. Alternative
suppliers have not been able to match that price (shopping credit) by a
sufficient margin in order to ensure profitability, particularly to the
industrial sector. Changes in electric generation sales and distribution deliveries in the
third quarter and the first nine months of 2004 from the corresponding periods
of 2003 are summarized in the following table: 154




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Changes in KWH Sales
    
    Three Months
    
    Nine MonthsIncrease (Decrease)Electric Generation:Retail
    
    
    3.8
    %
    
    
    4.4
    %Wholesale
    
    
    60.0
    %
    
    
    (100.0
    )%Total Electric Generation Sales
    
    
    3.8
    %
    
    
    4.4
    %Distribution Deliveries:Residential
    
    
    4.1
    %
    
    
    3.1
    %Commercial
    
    
    3.2
    %
    
    
    2.8
    %Industrial
    
    
    3.2
    %
    
    
    4.1
    %Total Distribution Deliveries
    
    
    3.5
    %
    
    
    3.3
    %
 Operating Expenses and Taxes Total operating expenses and taxes decreased $2 million in the third
quarter of 2004 and increased $11 million in the first nine 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
    
    Nine Months(In millions)Increase (Decrease)Purchased power costs
    
    $
    
    
    
    $
    13Other operating costs
    
    
    (12
    )
    
    
    (10
    )Total operation and maintenance expenses
    
    
    (12
    )
    
    
    3General taxes
    
    
    
    
    
    
    2Income taxes
    
    
    10
    
    
    
    6Total operating expenses and taxes
    
    $
    (2
    )
    
    $
    11
 Higher purchased power costs in the first nine months of 2004, compared
with the same period of 2003, were due to higher kilowatt-hour purchases to
meet increased generation sales requirements, partially offset by lower unit
costs. The decreases in other operating costs in the 2004 periods resulted
primarily from higher levels of energy delivery construction activities in
2004, compared to more maintenance activities last year, and lower payroll and
employee benefits costs. The decrease in other operating costs in the first
nine months of 2004 was partially offset by higher vegetation management costs. Net Interest Charges Net interest charges increased by $1 million in the third quarter of 2004
and $5 million in the first nine months of 2004 compared with 2003, primarily
due to Penelec changing from a net lender in 2003 to a net borrower in 2004 in
the money pool with associated companies. The change in funding position
resulted from a $51 million repayment to the 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, accretion offset by the reduction in
the existing decommissioning liabilities and ceasing the accounting practice of
depreciating non-regulated generation assets using a cost of removal component
was a $1.9 million increase to income, or $1.1 million net of income taxes. Capital Resources and Liquidity 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 September 30, 2004 and December 31, 2003 in
Penelecs cash and cash equivalents of $36,000. 155




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##### Table of Contents



Cash Flows From Operating Activities Net cash provided from (used for) operating activities during the third
quarter and first nine months of 2004 compared with the corresponding periods
of 2003, were as follows: Three Months Ended
    
    Nine Months EndedSeptember 30,
    
    September 30,Operating Cash Flows
    
    2004
    
    2003
    
    2004
    
    2003(In millions)Cash earnings (1)
    
    $
    47
    
    
    $
    25
    
    
    $
    76
    
    
    $
    35Pension trust contribution
    
    
    (50
    )
    
    
    
    
    
    
    (50
    )
    
    
    Working capital and other
    
    
    (25
    )
    
    
    (104
    )
    
    
    (7
    )
    
    
    (70
    )Total
    
    $
    (28
    )
    
    $
    (79
    )
    
    $
    19
    
    
    $
    (35
    )
  (1)
    
    Includes net income, depreciation and
amortization, deferred costs recoverable as
regulatory assets, deferred income taxes, investment
tax credits and major noncash charges. Net cash used for operating activities decreased $51 million in the third
quarter of 2004 compared to the same period of 2003 due to a $79 million
increase in working capital (primarily from changes in accounts payable,
receivables and prepayments) offset by a $50 million voluntary pension
contribution. The increase in cash earnings of $23 million is described above
under Results of Operations. Net cash provided from operating activities
increased $54 million in the first nine months of 2004 compared to the same
period of 2003 as a result of a $42 million increase in cash earnings and a $63
million increase in working capital (principally changes in accounts payable
and receivables) offset by the $50 million pension contribution. Cash Flows From Financing Activities Net cash provided from financing activities increased by $24 million in
the third quarter of 2004 from the third quarter of 2003. Net cash provided
from financing activities was $79 million for the first nine months of 2004
compared to net cash used for financing activities of $51 million in the first
nine months of 2003. Changes in both periods resulted from an increase in
short-term borrowings and a decrease in common stock dividends to FirstEnergy,
partially offset by a higher level of long-term debt redeemed in 2004. In March 2004, Penelec completed a receivables financing arrangement
providing 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 drawn in the third
quarter for $55 million and matures on March 29, 2005. On September 1, 2004, Penelec redeemed at par $100 million principal
amount of its subordinated debentures in connection with the concurrent
redemption at par of $100 million principal amount of 7.34% Penelec Capital
Trust Preferred Securities. As of September 30, 2004, Penelec had approximately $244 million of
short-term indebtedness, including $55 million drawn on its receivables
financing arrangement. Penelec has obtained authorization from the SEC to incur
short-term debt of up to $250 million (including the utility money pool). Under
the terms of its senior note indenture, Penelec is no longer permitted to issue
FMBs so long as senior notes are outstanding. Penelec has 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
third quarter of 2004 was 1.28%. 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 August 26, 2004, S&P
stated that a favorable outcome of FirstEnergys Ohio Rate Stabilization Plan
auction process and a favorable resolution of pending environmental litigation
would support a higher ratings outlook, or possibly a higher rating. S&P noted
that a ratings upgrade in 2004 does not appear likely because those major
issues would most likely not be resolved before the end of 2004. On September
14, 2004, S&P stated that FirstEnergys $500 million voluntary contribution to
its pension plan was credit neutral. Cash Flows From Investing Activities Net cash used for investing activities totaled $24 million in the third
quarter of 2004 compared to $51 million 156




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##### Table of Contents



provided from investing activities in the third quarter of 2003. Net cash used
for investing activities was $98 million in the first nine months of 2004,
compared with $76 million provided in the same period of 2003. The increase in
cash used for investing activities for both periods reflected decreased net
loan repayments from associated companies. The increase for the first nine
months of 2004 also resulted from a $51 million repayment to the NUG trust fund
in 2004 and a $106 million withdrawal from the NUG trust fund in 2003. During the last quarter of 2004, capital requirements for property
additions are expected to be about $25 million. Penelec has additional
requirements of approximately $0.2 million for maturing long-term debt during
the remainder of 2004. Those 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 third quarter and first nine months of 2004 is
summarized in the following table: Three Months Ended
    
    Nine Months EndedSeptember 30, 2004
    
    September 30, 2004Increase (Decrease) in the Fair Valueof Commodity Derivative Contracts
    
    Non-Hedge
    
    Hedge
    
    Total
    
    Non-Hedge
    
    Hedge
    
    Total(In millions)Change in the Fair Value of Commodity Derivative ContractsNet asset at beginning of period
    
    $
    15
    
    
    $
    
    
    
    $
    15
    
    
    $
    15
    
    
    $
    
    
    
    $
    15New contract value when entered
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Additions/Increase in value of existing contracts
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Change in techniques/assumptions
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Settled contracts
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Net Assets  Derivative Contracts as of September 30, 2004(1)
    
    $
    15
    
    
    $
    
    
    
    $
    15
    
    
    $
    15
    
    
    $
    
    
    
    $
    15Impact of Changes in Commodity Derivative Contracts (2)Income Statement Effects (Pre-Tax)
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    Balance Sheet Effects:Other Comprehensive Income (Pre-Tax)
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    Regulatory Liability
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    
  (1) Includes $14 million in non-hedge commodity derivative contracts which
are offset by a regulatory liability.  (2) Represents the increase in value of existing contracts, settled contracts
and changes in techniques/assumptions. Derivatives included on the Consolidated Balance Sheet as of September 30,
2004: Non-Hedge
    
    Hedge
    
    Total(In millions)Current-Other Assets
    
    $
    
    
    
    $
    
    
    
    $
    Other Liabilities
    
    
    
    
    
    
    
    
    
    
    Non-Current-Other Deferred Charges
    
    
    15
    
    
    
    
    
    
    
    15Other 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: 157




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Source of Information Fair Value by Contract Year
    
    2004(1)
    
    2005
    
    2006
    
    2007
    
    Thereafter
    
    Total(In millions)Prices based on external sources(2)
    
    $
    2
    
    
    $
    3
    
    
    $
    3
    
    
    $
    
    
    
    $
    
    
    
    $
    8Prices based on models(3)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2
    
    
    
    5
    
    
    
    7Total3
    
    $
    2
    
    
    $
    3
    
    
    $
    3
    
    
    $
    2
    
    
    $
    5
    
    
    $
    15
  (1) For the last quarter of 2004.  (2) Broker quote sheets.  (3) Includes $14 million from an embedded option that is offset by a regulatory
liability and does not affect earnings. 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 September 30, 2004. Equity Price Risk Included in Penelecs nuclear decommissioning trust investments are
marketable equity securities carried at their market value of approximately $54
million as of September 30, 2004 and December 31, 2003. A hypothetical 10%
decrease in prices quoted by stock exchanges would result in a $5 million
reduction in fair value as of September 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 transmission and distribution systems, which
remain 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 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 million. 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 158




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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. Penelecs
regulatory assets were $294 million and $497 million as of September 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 are 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 September 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. Power Outages and Related Litigation On August 14, 2003, various states and parts of southern Canada
experienced widespread power outages. The outages affected approximately 1.4
million customers in FirstEnergys service area. On April 5, 2004, the U.S.
Canada Power System Outage Task Force released its final report on the
outages. In the final report, the Task Force concluded, among other things,
that the problems leading to the outages began in FirstEnergys Ohio service
area. Specifically, the final report concludes, among other things, that the
initiation of the August 14, 2003 power outages resulted from an alleged
failure of both FirstEnergy and ECAR to assess and understand perceived
inadequacies within the FirstEnergy system; inadequate situational awareness of
the developing conditions; and a perceived failure to adequately manage tree
growth in certain transmission rights of way. The Task Force also concluded
that there was a failure of the interconnected grids reliability organizations
(MISO and PJM) to provide effective diagnostic support. The final report is
publicly available through the Department of Energys website (www.doe.gov).
FirstEnergy believes that the final report does not provide a complete and
comprehensive picture of the conditions that contributed to the August 14, 2003
power outages and that it does not adequately address the underlying causes of
the outages. FirstEnergy remains convinced that the outages cannot be explained
by events on any one utilitys system. The final report contains 46
recommendations to prevent or minimize the scope of future blackouts.
Forty-five of those recommendations relate to broad industry or policy matters
while one, including subparts, relates to activities the Task Force recommends
be undertaken by FirstEnergy, MISO, PJM, and ECAR. FirstEnergy implemented
several initiatives, both prior to and since the August 14, 2003 power outages,
which are consistent with these and other recommendations and collectively
enhance the reliability of its electric system. FirstEnergy certified to NERC
on June 30, 2004, completion of various reliability recommendations and further
received independent verification of completion status from a NERC verification
team on July 14, 2004 (see 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 159




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initiatives already were in process and budgeted in 2004, FirstEnergy does not
believe that any incremental expenses associated with additional initiatives
undertaken during 2004 will have a material effect on its operations or
financial results. FirstEnergy notes, however, that the applicable government
agencies and reliability coordinators may take a different view as to
recommended enhancements or may recommend additional enhancements in the future
that could require additional, material expenditures. FirstEnergy has not
accrued a liability as of September 30, 2004 for any expenditures in excess of
those actually incurred through that date. FirstEnergy is vigorously defending these actions, but cannot predict the
outcome of any of these proceedings or whether any further regulatory
proceedings or legal actions may be instituted against the Companies. In
particular, if FirstEnergy or its subsidiaries were ultimately determined to
have legal liability in connection with these proceedings, it could have a
material adverse effect on FirstEnergys or its subsidiaries financial
condition and results of operations. Reliability Initiatives On October 15, 2003, NERC issued a letter to all NERC control areas and
reliability coordinators requesting a review of various reliability practices.
The Company response confirmed that its review was completed and that various
enhancements were underway to current practices. On February 10, 2004, NERC
issued its Recommended Actions to Prevent and Mitigate the Impacts of Future
Cascading Blackouts, a portion of which were directed at the FirstEnergy
companies and broadly focused on initiatives that were recommended for
completion by June 30, 2004. FirstEnergys detailed implementation plan was
endorsed by the NERC Board of Trustees on May 7, 2004. The various initiatives
recommended by NERC were certified as complete by June 30, 2004, with one minor
exception related to reactive testing of certain generators expected to be
completed later in 2004. On April 5, 2004, the U.S.  Canada Power System Outage Task Force issued
a Final Report on the August 14, 2003 power outages. The Final Report contains
46 recommendations to prevent or minimize the scope of future blackouts.
Forty-five of those recommendations relate to broad industry or policy matters
while one relates to activities the Task Force recommended be undertaken by
FirstEnergy, MISO, PJM and ECAR. FirstEnergy completed the Task Force
recommendations that were directed toward FirstEnergy and reported completion
of those activities on June 30, 2004. With respect to each of the foregoing initiatives, FirstEnergy requested
and NERC provided, a technical assistance team of experts to provide ongoing
guidance and assistance in implementing and confirming timely and successful
completion. NERC further assembled an independent verification team to confirm
implementation of the foregoing initiatives required to be completed as of June
30, 2004. The NERC Verification Team reported, on July 14, 2004, that
FirstEnergy has completed the recommended policies, procedures and actions
required to be completed by June 30, 2004 or summer 2004, with exceptions noted
by FirstEnergy. Implementation of the recommendations has not required
incremental material investment or upgrades to existing equipment. 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.
FirstEnergy 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. Hearings were held in early August 2004. On September 30, 2004,
Penelec filed a settlement agreement with the PPUC that addresses the issues
related to this investigation. As part of the settlement, Penelec agreed to
enhance service reliability, performance reporting and communications with
customers and together with Met-Ed and Penn, to collectively maintain their
current spending levels of at least $255 million annually on combined capital
and operation and maintenance expenditures for transmission and distribution
for the years 2005 through 2007. In November 2004, the PPUC accepted
the recommendation of the ALJ approving the settlement. 160




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Legal Matters

Various lawsuits, claims (including claims for asbestos exposure) and
proceedings related to Penelecs normal business operations are pending against
Penelec, 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 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 postretirement 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

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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 in the first
nine months 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. In the third quarter of 2004, FirstEnergy made a $500 million voluntary
contribution ($50 million funded by Penelec) to its pension plan. This
contribution will mitigate future funding requirements and significantly reduce
the year-end minimum pension liability that currently reduces Penelecs
accumulated other comprehensive income by $42 million. 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 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 2004, 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 162




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the first nine 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 September 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 In March 2004, the EITF reached a consensus on the application guidance
for Issue 03-1. EITF 03-1 provides a model for determining when investments in
certain debt and equity securities are considered other than temporarily
impaired. When an impairment is other-than-temporary, the investment must be
measured at fair value and the impairment loss recognized in earnings. The
recognition and measurement provisions of EITF 03-1, which were to be effective
for periods beginning after June 15, 2004, were delayed by the issuance of FSP
EITF 03-1-1 in September 2004.  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 consolidated financial statements. See Note
2  Consolidation for a discussion of variable interest entities. 163




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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 September 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. 164




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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 2. CHANGES IN SECURITIES, USE OF PROCEEDS AND ISSUER PURCHASES OF EQUITY SECURITIES (e) FirstEnergy The table below includes information on a monthly basis regarding
purchases made by FirstEnergy of its common stock. Maximum Number(or ApproximateTotal Number of
    
    Dollar Value) ofShares Purchased
    
    Shares that MayTotal Number
    
    
    
    
    
    As Part of Publicly
    
    Yet Be Purchasedof Shares
    
    Average Price
    
    Announced Plans
    
    Under the PlansPeriod
    
    Purchased (a)
    
    Paid per Share
    
    or Programs (b)
    
    or ProgramsJanuary 1-31, 2004
    
    
    1,063,466
    
    
    $
    37.41
    
    
    
    
    
    
    
    February 1-29, 2004
    
    
    151,444
    
    
    $
    37.64
    
    
    
    
    
    
    
    March 1-31, 2004
    
    
    1,287,432
    
    
    $
    38.64
    
    
    
    
    
    
    
    First Quarter
    
    
    2,502,342
    
    
    $
    38.06
    
    
    
    
    
    
    
    April 1-30, 2004
    
    
    236,872
    
    
    $
    38.87
    
    
    
    
    
    
    
    May 1-31, 2004
    
    
    53,791
    
    
    $
    38.61
    
    
    
    
    
    
    
    June 1-30, 2004
    
    
    429,240
    
    
    $
    39.10
    
    
    
    
    
    
    
    Second Quarter
    
    
    719,903
    
    
    $
    38.99
    
    
    
    
    
    
    
    July 1-31, 2004
    
    
    80,447
    
    
    $
    38.26
    
    
    
    
    
    
    
    August 1-31, 2004
    
    
    324,616
    
    
    $
    39.88
    
    
    
    
    
    
    
    September 1-30, 2004
    
    
    521,084
    
    
    $
    41.01
    
    
    
    
    
    
    
    Third Quarter
    
    
    926,147
    
    
    $
    40.38
    
    
    
    
    
    
    
    Nine Months EndedSeptember 30, 2004
    
    
    4,148,392
    
    
    $
    38.74
    
    
    
    
    
    
    
    
  (a)
    
    Share amounts reflect purchases on the open market to satisfy
FirstEnergys obligations to deliver common stock under its Executive and
Director Incentive Compensation Plan, Deferred Compensation Plan for
Outside Directors, Executive Deferred Compensation Plan, Savings Plan and
Stock Investment Plan. In addition, such amounts reflect shares tendered
by employees to pay the exercise price or withholding taxes upon exercise
of stock options granted under the Executive and Director Incentive
Compensation Plan.(b)
    
    FirstEnergy does not currently have any publicly announced plan or
program for share purchases. 
 ITEM 6. EXHIBITS (a) Exhibits ExhibitNumberMet-Ed12
    
    Fixed charge ratios31.1
    
    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.Penelec12
    
    Fixed charge ratios15
    
    Letter from independent registered public accounting firm31.1
    
    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&L12
    
    Fixed charge ratios31.2
    
    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.FirstEnergy10-41
    
    Employment agreement between FirstEnergy Corp. and an officer dated July 20, 2004.10-42
    
    Stock option agreement between FirstEnergy Corp. and an officer dated August 20, 2004,10-43
    
    Restricted stock agreement between FirstEnergy Corp. and an officer dated August 20, 2004.10-44
    
    Executive bonus plan between FirstEnergy Corp. and officers dated October 31, 2004.15
    
    Letter from independent registered public accounting firm31.1
    
    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 Penn15
    
    Letter from independent registered public accounting firm31.1
    
    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.CEI4-1(85)
    
    Supplemental indenture dated as of September 1, 2004 between CEI and JPMorgan Chase Bank, as Trustee.4-1(86)
    
    Supplemental indenture dated as of October 1, 2004 between CEI and JPMorgan Chase Bank, as Trustee.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.
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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. 166




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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. November 4, 2004 FIRSTENERGY CORP.RegistrantOHIO EDISON COMPANYRegistrantTHE CLEVELAND ELECTRIC ILLUMINATING COMPANYRegistrantTHE TOLEDO EDISON COMPANYRegistrantPENNSYLVANIA POWER COMPANYRegistrantJERSEY CENTRAL POWER & LIGHT COMPANYRegistrantMETROPOLITAN EDISON COMPANYRegistrantPENNSYLVANIA ELECTRIC COMPANYRegistrant/s/ Harvey L. WagnerHarvey L. WagnerVice President, Controllerand Chief Accounting Officer
 167