FIRSTENERGY CORP.
Table of Contents

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

(Mark One)

[X]   QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2004

OR

     
[  ]   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

For the transition period from                     to                    

         
Commission   Registrant; State of Incorporation;   I.R.S. Employer
File Number
  Address; and Telephone Number
  Identification No.
333-21011
  FIRSTENERGY CORP.   34-1843785
 
  (An Ohio Corporation)    
 
  76 South Main Street    
 
  Akron, OH 44308    
 
  Telephone (800)736-3402    
 
       
1-2578
  OHIO EDISON COMPANY   34-0437786
 
  (An Ohio Corporation)    
 
  76 South Main Street    
 
  Akron, OH 44308    
 
  Telephone (800)736-3402    
 
       
1-2323
  THE CLEVELAND ELECTRIC ILLUMINATING COMPANY   34-0150020
 
  (An Ohio Corporation)    
 
  c/o FirstEnergy Corp.    
 
  76 South Main Street    
 
  Akron, OH 44308    
 
  Telephone (800)736-3402    
 
       
1-3583
  THE TOLEDO EDISON COMPANY   34-4375005
 
  (An Ohio Corporation)    
 
  c/o FirstEnergy Corp.    
 
  76 South Main Street    
 
  Akron, OH 44308    
 
  Telephone (800)736-3402    
 
       
1-3491
  PENNSYLVANIA POWER COMPANY   25-0718810
 
  (A Pennsylvania Corporation)    
 
  c/o FirstEnergy Corp.    
 
  76 South Main Street    
 
  Akron, OH 44308    
 
  Telephone (800)736-3402    
 
       
1-3141
  JERSEY CENTRAL POWER & LIGHT COMPANY   21-0485010
 
  (A New Jersey Corporation)    
 
  c/o FirstEnergy Corp.    
 
  76 South Main Street    
 
  Akron, OH 44308    
 
  Telephone (800)736-3402    
 
       
1-446
  METROPOLITAN EDISON COMPANY   23-0870160
 
  (A Pennsylvania Corporation)    
 
  c/o FirstEnergy Corp.    
 
  76 South Main Street    
 
  Akron, OH 44308    
 
  Telephone (800)736-3402    
 
       
1-3522
  PENNSYLVANIA ELECTRIC COMPANY   25-0718085
 
  (A Pennsylvania Corporation)    
 
  c/o FirstEnergy Corp.    
 
  76 South Main Street    
 
  Akron, OH 44308    
 
  Telephone (800)736-3402    

 


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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:

         
    OUTSTANDING
CLASS
  AS OF NOVEMBER 4, 2004
FirstEnergy Corp., $.10 par value
    329,836,276  
Ohio Edison Company, no par value
    100  
The Cleveland Electric Illuminating Company, no par value
    79,590,689  
The Toledo Edison Company, $5 par value
    39,133,887  
Pennsylvania Power Company, $30 par value
    6,290,000  
Jersey Central Power & Light Company, $10 par value
    15,371,270  
Metropolitan Edison Company, no par value
    859,500  
Pennsylvania Electric Company, $20 par value
    5,290,596  

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

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

     This Form 10-Q includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties. These statements typically contain, but are not limited to, the terms “anticipate”, “potential”, “expect”, “believe”, “estimate” and similar words. Actual results may differ materially due to the speed and nature of increased competition and deregulation in the electric utility industry, economic or weather conditions affecting future sales and margins, changes in markets for energy services, changing energy and commodity market prices, replacement power costs being higher than anticipated or inadequately hedged, maintenance costs being higher than anticipated, legislative and regulatory changes (including revised environmental requirements), adverse regulatory or legal decisions and the outcome of governmental investigations (including revocation of necessary licenses or operating permits), availability and cost of capital, the continuing availability and operation of generating units, the inability to accomplish or realize anticipated benefits of strategic goals, the ability to improve electric commodity margins and to experience growth in the distribution business, the ability to access the public securities markets, further investigation into the causes of the August 14, 2003 regional power 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

     
    Pages
  i-iii
 
   
 
Items 1. and 2. - Financial Statements and Management’s Discussion and Analysis of Results of Operation and Financial Condition
   
 
  1-25
 
FirstEnergy Corp.
   
 
  26
  27
  28
  29
  30
  31-63
 
Ohio Edison Company
   
 
  64
  65
  66
  67
  68-79
 
The Cleveland Electric Illuminating Company
   
 
  80
  81
  82
  83
  84-94
 
The Toledo Edison Company
   
 
  95
  96
  97
  98
  99-109
 
Pennsylvania Power Company
   
 
  110
  111
  112
  113
  114-121

 


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TABLE OF CONTENTS (Cont’d)

     
    Pages
Jersey Central Power & Light Company
   
 
   
  122
  123
  124
  125
  126-135
 
   
Metropolitan Edison Company
   
 
   
  136
  137
  138
  139
  140-149
 
   
Pennsylvania Electric Company
   
 
   
  150
  151
  152
  153
  154-163
 
   
  164
 
   
  164
 
   
   
 
   
  165
 
   
  165
 
   
  165-166
 EX-4.1.85 85TH SUPP IND
 EX-4.1.86 86TH SUPP IND
 EX-4.2.56 54TH SUPP IND
 EX-10.41 EMPLOYMENT AGREEMENT
 EX-10.42 NON-QUALIFYING
 EX-10.43 RESTRICTED STOCK
 EX-10.44 EXECUTIVE BONUS PLAN
 EX-12 RATIO OF EARNINGS
 EX-15 ACCOUNTANTS REPORT
 EX-31.1 CERTIFICATION CEO
 EX-31.2 CERTIFICATION CFO
 EX-31.3 CERTIFICATION
 EX-32.1 RULE 906-CEO
 EX-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 facilities    
Avon
  Avon Energy Partners Holdings    
CEI
  The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary    
CFC
  Centerior Funding Corporation, a wholly owned finance subsidiary of CEI    
Companies
  OE, CEI, TE, Penn, JCP&L, Met-Ed and Penelec    
Emdersa   Empresa Distribuidora Electrica Regional S.A.
EUOC
  Electric Utility Operating Companies (OE, CEI, TE, Penn, JCP&L, Met-Ed, Penelec, and ATSI)    
FENOC
  FirstEnergy Nuclear Operating Company, operates nuclear generating facilities    
FES
  FirstEnergy Solutions Corp., provides energy-related products and services    
FESC
  FirstEnergy Service Company, provides legal, financial, and other corporate support services    
FGCO
  FirstEnergy Generation Corp., operates nonnuclear generating facilities    
FirstCom
  First Communications, LLC, provides local and long-distance telephone service    
FirstEnergy
  FirstEnergy Corp., a registered public utility holding company    
FSG
  FirstEnergy Facilities Services Group, LLC, the parent company of several heating, ventilation air conditioning and energy management companies    
GLEP
  Great Lakes Energy Partners, LLC, an oil and natural gas exploration and production venture    
GPU
  GPU, Inc., former parent of JCP&L, Met-Ed and Penelec, which merged with FirstEnergy on November 7, 2001    
GPU Capital
  GPU Capital, Inc., owned and operated electric distribution systems in foreign countries    
GPU Power
  GPU Power, Inc., owned and operated generation facilities in foreign countries    
GPUS
  GPU Service Company, previously provided corporate support services    
JCP&L
  Jersey Central Power & Light Company, a New Jersey electric utility operating subsidiary    
JCP&L Transition
  JCP&L Transition Funding LLC, a Delaware limited liability company and issuer of transition bonds    
MARBEL
  MARBEL Energy Corporation, previously held FirstEnergy’s interest in GLEP    
Met-Ed
  Metropolitan Edison Company, a Pennsylvania electric utility operating subsidiary    
MYR
  MYR Group, Inc., a utility infrastructure construction service company    
NEO
  Northeast Ohio Natural Gas Corp., formerly a MARBEL subsidiary    
OE
  Ohio Edison Company, an Ohio electric utility operating subsidiary    
OE Companies
  OE and Penn    
Ohio Companies
  CEI, OE and TE    
Penelec
  Pennsylvania Electric Company, a Pennsylvania electric utility operating subsidiary    
Penn
  Pennsylvania Power Company, a Pennsylvania electric utility operating subsidiary of OE    
PNBV
  PNBV Capital Trust, a special purpose entity created by OE in 1996    
Shippingport
  Shippingport Capital Trust, a special purpose entity created by CEI and TE in 1997    
TE
  The Toledo Edison Company, an Ohio electric utility operating subsidiary    
TEBSA
  Termobarranquilla S.A., Empresa de Servicios Publicos    
TECC
  Toledo Edison Capital Corporation, a 90% owned subsidiary of TE    

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

     
ALJ
  Administrative Law Judge
AOCL
  Accumulated Other Comprehensive Loss
APB
  Accounting Principles Board
APB 25
  APB Opinion No. 25, “Accounting for Stock Issued to Employees”
ARB 51
  Accounting Research Bulletin No. 51, “Consolidated Financial Statements”
ARO
  Asset Retirement Obligation
ASLB
  Atomic Safety and Licensing Board
BGS
  Basic Generation Service
CO2
  Carbon Dioxide
CTA
  Currency Translation Adjustment
CTC
  Competitive Transition Charge
ECAR
  East Central Area Reliability Agreement
EITF
  Emerging Issues Task Force
EITF 03-1
  EITF Issue No. 03-1, “The Meaning of Other-Than-Temporary and Its Application to Certain Investments”
EITF 03-16
  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”

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GLOSSARY OF TERMS, Cont.

     
EPA
  Environmental Protection Agency
FASB
  Financial Accounting Standards Board
FCON 7
  FASB Concepts Statement No. 7, “Using Cash Flow Information and Present Value in Accounting Measurements”
FERC
  Federal Energy Regulatory Commission
FIN
  FASB Interpretation
FIN 46R
  FIN 46 (revised December 2003), “Consolidation of Variable Interest Entities”
FMB
  First Mortgage Bonds
FSP
  FASB Staff Position
FSP 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 States
HVAC
  Heating, Ventilation and Air-conditioning
IRS
  Internal Revenue Service
ISO
  Independent System Operator
KWH
  Kilowatt-hours
LOC
  Letter of Credit
MACT
  Maximum Achievable Control Technologies
Medicare Act
  Medicare Prescription Drug, Improvement and Modernization Act of 2003
MISO
  Midwest Independent System Operator, Inc.
Moody’s
  Moody’s Investors Service
MTC
  Market Transition Charge
MTN
  Medium Term Note
MW
  Megawatts
NAAQS
  National Ambient Air Quality Standards
NERC
  North American Electric Reliability Council
NJBPU
  New Jersey Board of Public Utilities
NOV
  Notices of Violation
NOX
  Nitrogen Oxide
NRC
  Nuclear Regulatory Commission
NUG
  Non-Utility Generation
OCC
  Ohio Consumers’ Counsel
OCI
  Other Comprehensive Income
OPEB
  Other Post-Employment Benefits
PCAOB
  Public Company Accounting Oversight Board (United States)
PJM
  PJM Interconnection ISO
PLR
  Provider of Last Resort
PPUC
  Pennsylvania Public Utility Commission
PRP
  Potentially Responsible Party
PUCO
  Public Utilities Commission of Ohio
PUHCA
  Public Utility Holding Company Act
RTC
  Regulatory Transition Charge
S&P
  Standard & Poor’s Ratings Service
SBC
  Societal Benefits Charge
SEC
  United States Securities and Exchange Commission
SFAS
  Statement of Financial Accounting Standards
SFAS 71
  SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation”
SFAS 87
  SFAS No. 87, “Employers’ Accounting for Pensions”
SFAS 95
  SFAS No. 95, “Statement of Cash Flows”
SFAS 106
  SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions”
SFAS 123
  SFAS No. 123, “Accounting for Stock-Based Compensation”
SFAS 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”

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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 Plan
SO2
  Sulfur Dioxide
SPE
  Special Purpose Entity
TBC
  Transition Bond Charge
TMI-1
  Three Mile Island Unit 1
TMI-2
  Three Mile Island Unit 2
VIE
  Variable Interest Entity

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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.

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

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

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

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

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

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

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

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

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

          FirstEnergy has evaluated its power purchase agreements and determined that certain NUG entities may be VIEs to the extent they own a plant that sells substantially all of its output to the Companies and the contract price for power is correlated with the plant’s variable costs of production. FirstEnergy, through its subsidiaries JCP&L, Met-Ed and

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

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

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

                                 
    Three Months Ended   Nine Months Ended
    September 30,
  September 30,
    2004
  2003
  2004
  2003
            (In millions)        
JCP&L
  $ 36     $ 31     $ 99     $ 89  
Met-Ed
    13       12       38       39  
Penelec
    7       7       20       20  
 
   
 
     
 
     
 
     
 
 
Total
  $ 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 Ended
Reconciliation 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     $ 276,408  
Average Shares of Common Stock Outstanding:
                               
Denominator for basic earnings per share (weighted average shares outstanding)
    327,499       299,422       327,280       295,825  
Assumed exercise of dilutive stock options and awards
    1,600       1,329       1,570       1,328  
 
   
 
     
 
     
 
     
 
 
Denominator for diluted earnings per share
    329,099       300,751       328,850       297,153  
 
   
 
     
 
     
 
     
 
 
Income Before Discontinued Operations and Cumulative Effect of Accounting Change, per common share:
                               
Basic
  $ 0.91     $ 0.51     $ 2.07     $ 0.93  
Diluted
  $ 0.91     $ 0.50     $ 2.06     $ 0.93  

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     Preferred Stock Subject to Mandatory Redemption

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

     Securitized Transition Bonds

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

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

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

     Derivative Accounting

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

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

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

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

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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 Reconciliation
                                               
Balance as of December 31, 2003
  $ 6,128     $ 1,694     $ 505     $ 2,001     $ 884     $ 899  
Adjustments 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).

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

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

                                                                 
Three Months
  FirstEnergy
  OE
  CEI
  TE
  Penn
  JCP&L
  Met-Ed
  Penelec
    (In millions)
ARO Reconciliation
                                                               
Balance, July 1, 2004
  $ 1,217     $ 194     $ 263     $ 188     $ 134     $ 113     $ 216     $ 108  
Liabilities incurred
                                               
Liabilities settled
                                               
Accretion
    19       4       5       3       2       2       3       1  
Revisions in estimated cash flows
    (176 )                             (43 )     (89 )     (44 )
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
     
 
 
Balance, September 30, 2004
  $ 1,060     $ 198     $ 268     $ 191     $ 136     $ 72     $ 130     $ 65  
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
     
 
 
Balance, July 1, 2003
  $ 1,145     $ 182     $ 246     $ 178     $ 126     $ 107     $ 204     $ 102  
Liabilities incurred
                                               
Liabilities settled
                                               
Accretion
    16       3       5       1       1       1       3       2  
Revisions 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 Reconciliation
                                                               
Balance, January 1, 2004
  $ 1,179     $ 188     $ 255     $ 182     $ 130     $ 110     $ 210     $ 105  
Liabilities incurred
                                               
Liabilities settled
                                               
Accretion
    57       10       13       9       6       5       9       4  
Revisions in estimated cash flows
    (176 )                             (43 )     (89 )     (44 )
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
     
 
 
Balance, September 30, 2004
  $ 1,060     $ 198     $ 268     $ 191     $ 136     $ 72     $ 130     $ 65  
 
   
 
     
 
     
 
     
 
     
 
     
 
     
 
     
 
 
Balance, January 1, 2003
  $ 1,109     $ 176     $ 238     $ 172     $ 122     $ 104     $ 198     $ 99  
Liabilities incurred
                                               
Liabilities settled
                                               
Accretion
    52       9       13       7       5       4       9       5  
Revisions 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.

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Table of Contents

                                 
    Three Months Ended   Nine Months Ended
    September 30,
  September 30,
    2004
  2003
  2004
  2003
    (In thousands)   (In thousands)
Net income, as reported
  $ 298,622     $ 152,719     $ 676,666     $ 313,333  
Add back compensation expense reported in net income, net of tax (based on APB 25)
          40             131  
Deduct 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     $ 304,150  
 
   
 
     
 
     
 
     
 
 
Earnings Per Share of Common Stock –
                               
Basic
                               
As Reported
  $ 0.91     $ 0.51     $ 2.07     $ 1.06  
Adjusted
  $ 0.90     $ 0.50     $ 2.03     $ 1.03  
Diluted
                               
As Reported
  $ 0.91     $ 0.50     $ 2.06     $ 1.05  
Adjusted
  $ 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     $ 93  
Accumulated depreciation
    25       7       6       9       98       186       93  
Asset retirement obligation
    298       238       172       121       104       198       99  
Cumulative effect adjustment, pretax
    54       73       44       18             0.4       2  
Cumulative effect adjustment, net of tax
    32       42       26       11             0.2       1  

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

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

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

TE

                                 
    Three Months Ended   Nine Months Ended
    September 30, 2003
  September 30, 2003
    As Previously   As   As Previously   As
    Reported
  Restated
  Reported
  Restated
            (In thousands)        
Operating revenues
  $ 260,190     $ 260,197     $ 708,000     $ 708,007  
Operating expenses
    241,987       241,447       686,400       685,813  
 
   
 
     
 
     
 
     
 
 
Operating income
    18,203       18,750       21,600       22,194  
Other income
    5,768       5,724       12,644       12,600  
Net interest charges
    8,220       7,872       29,605       27,982  
 
   
 
     
 
     
 
     
 
 
Income before cumulative effect of accounting change
    15,751       16,602       4,639       6,812  
Cumulative effect of accounting change
                25,550       25,550  
 
   
 
     
 
     
 
     
 
 
Net income
    15,751       16,602       30,189       32,362  
Preferred stock dividend requirements
    2,211       2,211       6,627       6,627  
 
   
 
     
 
     
 
     
 
 
Earnings attributable to common stock
  $ 13,540     $ 14,391     $ 23,562     $ 25,735  
 
   
 
     
 
     
 
     
 
 

JCP&L

                                 
    Three Months Ended   Nine Months Ended
    September 30, 2003
  September 30, 2003
    As Previously   As   As Previously   As
    Reported
  Restated
  Reported
  Restated
            (In thousands)        
Operating revenues
  $ 743,145     $ 741,293     $ 1,942,868     $ 1,941,016  
Operating expenses
    659,526       653,761       1,807,539       1,799,876  
 
   
 
     
 
     
 
     
 
 
Operating income
    83,619       87,532       135,329       141,140  
Other income
    1,061       557       4,501       3,997  
Net interest charges
    20,517       20,517       65,429       65,429  
 
   
 
     
 
     
 
     
 
 
Net income
    64,163       67,572       74,401       79,708  
Preferred stock dividend requirements
    125       125       (238 )     (238 )
 
   
 
     
 
     
 
     
 
 
Earnings attributable to common stock
  $ 64,038     $ 67,447     $ 74,639     $ 79,946  
 
   
 
     
 
     
 
     
 
 

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Penelec

                                 
    Three Months Ended   Nine Months Ended
    September 30, 2003
  September 30, 2003
    As Previously   As   As Previously   As
    Reported
  Restated
  Reported
  Restated
            (In thousands)        
Operating revenues
  $ 242,960     $ 242,146     $ 729,762     $ 728,948  
Operating expenses
    230,484       228,476       688,725       686,311  
 
   
 
     
 
     
 
     
 
 
Operating income
    12,476       13,670       41,037       42,637  
Other income
    545       522       887       864  
Net interest charges
    9,046       9,046       25,451       25,451  
 
   
 
     
 
     
 
     
 
 
Income before cumulative effect of accounting change
    3,975       5,146       16,473       18,050  
Cumulative effect of accounting change
                1,096       1,096  
 
   
 
     
 
     
 
     
 
 
Net 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 Paid    
    Total  
  Remaining
Collateral Provisions
  Exposure(1)
  Cash
  Letters of Credit
  Exposure
            (In millions)        
Rating downgrade
  $ 358     $ 145     $ 18     $ 195  
Adverse event
    113             23       90  
 
   
 
     
 
     
 
     
 
 
Total
  $ 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.

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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

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

     Mercury Emissions

          In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. On December 15, 2003, the EPA proposed two different approaches to reduce mercury emissions from coal-fired power plants. The first approach would require plants to install controls known as MACT based on the type of coal burned. According to the EPA, if implemented, the MACT proposal would reduce nationwide mercury emissions from coal-fired power plants by 14 tons to approximately 34 tons per year. The second approach proposes a cap-and-trade program that would reduce mercury emissions in two distinct phases. Initially, mercury emissions would be reduced by 2010 as a “co-benefit” from implementation of SO2 and 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.

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     Climate Change

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

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

     Clean Water Act

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

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

     Power Outages and Related Litigation

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

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

          On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy’s service area. On April 5, 2004, the U.S. –Canada Power System Outage Task Force released its final report on the outages. In the final report, the Task Force concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concludes, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid’s reliability organizations (MISO and PJM) to provide effective diagnostic support. The final report is publicly available through the Department of Energy’s website (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility’s system. The final report contains 46

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

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

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

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

     Nuclear Plant Matters

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

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

     Other Legal Matters

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

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

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

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

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

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

4 — PENSION AND OTHER POSTRETIREMENT BENEFITS:

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

                                 
    Three Months Ended   Nine Months Ended
    September 30,
  September 30,
Pension Benefits
  2004
  2003
  2004
  2003
            (In millions)        
Service cost
  $ 19     $ 17     $ 58     $ 51  
Interest cost
    63       65       189       194  
Expected return on plan assets
    (71 )     (64 )     (215 )     (191 )
Amortization of prior service cost
    2       2       7       7  
Recognized net actuarial loss
    10       16       29       48  
 
   
 
     
 
     
 
     
 
 
Net 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
  $ 60  
CEI
    32  
TE
    13  
Penn
    13  
JCP&L
    62  
Met-Ed
    39  
Penelec
    50  
All other subsidiaries
    231  
 
   
 
 
Total
  $ 500  
 
   
 
 

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

                                 
    Three Months Ended   Nine Months Ended
    September 30,
  September 30,
Other Postretirement Benefits
  2004
  2003
  2004
  2003
            (In millions)        
Service cost
  $ 9     $ 16     $ 27     $ 49  
Interest cost
    26       96       83       290  
Expected return on plan assets
    (10 )     (95 )     (32 )     (285 )
Amortization of prior service cost
    (9 )     4       (28 )     11  
Recognized net actuarial loss
    9       24       29       72  
 
   
 
     
 
     
 
     
 
 
Net 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 Ended
    September 30,
  September 30,
Pension Benefit Cost
  2004
  2003
  2004
  2003
            (In millions)        
OE
  $ 1.7     $ 6.3     $ 5.2     $ 12.1  
Penn
    0.1       1.3       0.4       2.1  
CEI
    1.6       2.7       4.8       6.9  
TE
    0.8       1.4       2.3       3.5  
JCP&L
    1.9       3.2       5.6       14.2  
Met-Ed
    0.1       0.8       0.2       6.5  
Penelec
    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 Ended
    September 30,
  September 30,
Other Postretirement Benefit Cost
  2004
  2003
  2004
  2003
            (In millions)        
OE
  $ 5.7     $ 11.4     $ 17.7     $ 20.3  
Penn
    1.2       2.2       3.7       3.5  
CEI
    4.4       3.4       13.7       9.8  
TE
    1.7       1.3       5.0       4.5  
JCP&L
    1.0       3.7       3.5       16.2  
Met-Ed
    0.7       2.2       2.5       8.7  
Penelec
    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:

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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.

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

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

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

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

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

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

     Ohio

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

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

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

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

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

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

          Under that proposal, the Ohio Companies requested:

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

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

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

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

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

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

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

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

     Transition Cost Amortization

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

                                 
    FirstEnergy
  OE
  CEI
  TE
            (In millions)        
2004
  $ 754     $ 429     $ 200     $ 125  
2005
    841       475       225       141  
2006
    390       182       124       84  
2007
    315       85       141       89  
2008
    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

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

     New Jersey

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

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

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

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

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

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

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

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

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

     Pennsylvania

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

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

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

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

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

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

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

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

7 - NEW ACCOUNTING STANDARDS AND INTERPRETATIONS:

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

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

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

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

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

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

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

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

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

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

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

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

8 - SEGMENT INFORMATION:

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

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

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

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

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Segment Financial Information

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

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FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

                                 
    Three Months Ended   Nine Months Ended
    September 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     $ 6,924,781  
Unregulated businesses
    1,009,348       897,056       2,994,092       2,571,869  
 
   
 
     
 
     
 
     
 
 
Total revenues
    3,536,319       3,422,814       9,868,666       9,496,650  
 
   
 
     
 
     
 
     
 
 
EXPENSES:
                               
Fuel and purchased power
    1,285,355       1,199,408       3,514,816       3,338,361  
Purchased gas
    96,836       105,213       353,327       453,824  
Other operating expenses
    917,345       946,847       2,641,870       2,813,191  
Provision for depreciation and amortization
    393,218       389,401       1,154,895       1,119,954  
Goodwill impairment (Note 2)
          116,988             116,988  
General taxes
    177,452       177,499       514,269       518,451  
 
   
 
     
 
     
 
     
 
 
Total expenses
    2,870,206       2,935,356       8,179,177       8,360,769  
 
   
 
     
 
     
 
     
 
 
NET INTEREST CHARGES:
                               
Interest expense
    152,703       199,106       505,448       598,645  
Capitalized interest
    (6,536 )     (6,513 )     (18,286 )     (23,287 )
Subsidiaries’ preferred stock dividends
    5,354       8,021       16,024       36,423  
 
   
 
     
 
     
 
     
 
 
Net interest charges
    151,521       200,614       503,186       611,781  
 
   
 
     
 
     
 
     
 
 
INCOME TAXES
    215,970       135,151       509,637       247,692  
 
   
 
     
 
     
 
     
 
 
INCOME BEFORE DISCONTINUED OPERATIONS AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE
    298,622       151,693       676,666       276,408  
Discontinued 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)
                      102,147  
 
   
 
     
 
     
 
     
 
 
NET INCOME
  $ 298,622     $ 152,719     $ 676,666     $ 313,333  
 
   
 
     
 
     
 
     
 
 
BASIC EARNINGS PER SHARE OF COMMON STOCK:
                               
Income before discontinued operations and cumulative effect of accounting change
  $ 0.91     $ 0.51     $ 2.07     $ 0.93  
Discontinued operations (net of income taxes) (Note 2)
                      (0.22 )
Cumulative effect of accounting change (net of income taxes) (Note 2)
                      0.35  
 
   
 
     
 
     
 
     
 
 
Net income
  $ 0.91     $ 0.51     $ 2.07     $ 1.06  
 
   
 
     
 
     
 
     
 
 
WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING
    327,499       299,422       327,280       295,825  
 
   
 
     
 
     
 
     
 
 
DILUTED EARNINGS PER SHARE OF COMMON STOCK:
                               
Income before discontinued operations and cumulative effect of accounting change
  $ 0.91     $ 0.50     $ 2.06     $ 0.93  
Discontinued operations (net of income taxes) (Note 2)
                      (0.22 )
Cumulative effect of accounting change (net of income taxes) (Note 2)
                      0.34  
 
   
 
     
 
     
 
     
 
 
Net income
  $ 0.91     $ 0.50     $ 2.06     $ 1.05  
 
   
 
     
 
     
 
     
 
 
WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING
    329,099       300,751       328,850       297,153  
 
   
 
     
 
     
 
     
 
 
DIVIDENDS 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.

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FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

                                 
    Three Months Ended   Nine Months Ended
    September 30,
  September 30,
    2004
  2003
  2004
  2003
            (In thousands)        
NET INCOME
  $ 298,622     $ 152,719     $ 676,666     $ 313,333  
 
OTHER 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       62,261  
Currency translation adjustments
          (11 )           91,450  
 
   
 
     
 
     
 
     
 
 
Other comprehensive income
    14,642       1,565       31,801       147,117  
Income 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       123,588  
 
   
 
     
 
     
 
     
 
 
COMPREHENSIVE 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.

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FIRSTENERGY CORP.

CONSOLIDATED BALANCE SHEETS
(Unaudited)

                 
    September 30,   December 31,
    2004
  2003
    (In thousands)
ASSETS
               
CURRENT ASSETS:
               
Cash and cash equivalents
  $ 67,892     $ 113,975  
Receivables-
               
Customers (less accumulated provisions of $48,031,000 and $50,247,000, respectively, for uncollectible accounts)
    1,020,756       1,000,259  
Other (less accumulated provisions of $28,392,000 and $12,851,000, respectively, for uncollectible accounts)
    371,865       505,241  
Materials and supplies, at average cost-
               
Owned
    346,455       325,303  
Under consignment
    95,728       95,719  
Prepayments and other
    216,618       202,814  
 
   
 
     
 
 
 
    2,119,314       2,243,311  
 
   
 
     
 
 
PROPERTY, PLANT AND EQUIPMENT:
               
In service
    21,979,434       21,594,746  
Less—Accumulated provision for depreciation
    9,294,783       9,105,303  
 
   
 
     
 
 
 
    12,684,651       12,489,443  
Construction work in progress
    653,718       779,479  
 
   
 
     
 
 
 
    13,338,369       13,268,922  
 
   
 
     
 
 
INVESTMENTS:
               
Nuclear plant decommissioning trusts
    1,461,893       1,351,650  
Investments in lease obligation bonds
    966,685       989,425  
Certificates of deposit
          277,763  
Other
    726,153       878,853  
 
   
 
     
 
 
 
    3,154,731       3,497,691  
 
   
 
     
 
 
DEFERRED CHARGES:
               
Regulatory assets
    5,792,517       7,076,923  
Goodwill
    6,100,969       6,127,883  
Other
    719,216       695,218  
 
   
 
     
 
 
 
    12,612,702       13,900,024  
 
   
 
     
 
 
 
  $ 31,225,116     $ 32,909,948  
 
   
 
     
 
 
LIABILITIES AND CAPITALIZATION
               
CURRENT LIABILITIES:
               
Currently payable long-term debt
  $ 674,901     $ 1,754,197  
Short-term borrowings
    302,508       521,540  
Accounts payable
    575,845       725,239  
Accrued taxes
    969,622       669,529  
Other
    959,475       801,662  
 
   
 
     
 
 
 
    3,482,351       4,472,167  
 
   
 
     
 
 
CAPITALIZATION:
               
Common stockholders’ equity-
               
Common stock, $0.10 par value, authorized 375,000,000 shares- 329,836,276 shares outstanding
    32,984       32,984  
Other paid-in capital
    7,055,997       7,062,825  
Accumulated other comprehensive loss
    (331,874 )     (352,649 )
Retained earnings
    1,913,305       1,604,385  
Unallocated 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       8,289,341  
Preferred stock of consolidated subsidiaries not subject to mandatory redemption
    335,123       335,123  
Long-term debt and other long-term obligations
    10,110,552       9,789,066  
 
   
 
     
 
 
 
    19,070,085       18,413,530  
 
   
 
     
 
 
NONCURRENT LIABILITIES:
               
Accumulated deferred income taxes
    2,019,446       2,178,075  
Asset retirement obligations
    1,060,290       1,179,493  
Power purchase contract loss liability
    2,173,888       2,727,892  
Retirement benefits
    1,197,903       1,591,006  
Lease market valuation liability
    957,450       1,021,000  
Other
    1,263,703       1,326,785  
 
   
 
     
 
 
 
    8,672,680       10,024,251  
 
   
 
     
 
 
COMMITMENTS, 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.

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FIRSTENERGY CORP.
 

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
                                 
    Three Months Ended   Nine Months Ended
    September 30,
  September 30,
    2004
  2003
  2004
  2003
            (In thousands)        
CASH FLOWS FROM OPERATING ACTIVITIES:
                               
Net income
  $ 298,622     $ 152,719     $ 676,666     $ 313,333  
Adjustments to reconcile net income to net cash from operating activities-
                               
Provision for depreciation and amortization
    393,218       389,401       1,154,895       1,119,954  
Nuclear fuel and lease amortization
    26,776       16,902       71,782       47,398  
Other 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             116,988  
Accrued retirement benefit obligations
    42,397       81,819       106,897       229,172  
Accrued compensation, net
    26,592       (440 )     48,186       (70,976 )
Revenue credits to customers
          (19,583 )           (71,984 )
Disallowed regulatory assets
                      152,500  
Cumulative effect of accounting change
                      (174,663 )
Loss (income) from discontinued operations
          (1,026 )           65,222  
Commodity 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       43,959  
Materials 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       210,115  
Accrued interest
    82,576       68,357       76,210       51,898  
NUG 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       1,304,933  
 
   
 
     
 
     
 
     
 
 
CASH FLOWS FROM FINANCING ACTIVITIES:
                               
New Financing-
                               
Common Stock
          934,605             934,605  
Long-term debt
    86,754             961,474       771,637  
Redemptions 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 )     31,352  
Common 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 )     106,327  
Contribution to nuclear decommissioning trusts
    (25,370 )     (47,622 )     (76,112 )     (75,873 )
Proceeds from asset sales
    1,662       1,081       213,109       67,530  
Proceeds from note receivable
                      19,000  
Cash investments
    (7,316 )     31,696       19,640       46,761  
Proceeds from certificates of deposit
    277,763             277,763        
Other
    (30,838 )     (48,124 )     (4,311 )     28,851  
 
   
 
     
 
     
 
     
 
 
Net 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 )     13,962  
Cash and cash equivalents at beginning of period
    99,538       127,556       113,975       225,932  
 
   
 
     
 
     
 
     
 
 
Cash 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.

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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

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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

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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.

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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 Ended
    September 30,
  September 30,
FirstEnergy
  2004
  2003
  2004
  2003
            (In millions)        
Total revenues
  $ 3,536     $ 3,423     $ 9,869     $ 9,497  
Income before discontinued operations and cumulative effect of accounting change
    299       152       677       276  
Discontinued operations
          1             (65 )
Cumulative effect of accounting change
                      102  
 
   
 
     
 
     
 
     
 
 
Net Income
  $ 299     $ 153     $ 677     $ 313  
 
   
 
     
 
     
 
     
 
 
Basic Earnings Per Share:
                               
Income before discontinued operations and cumulative effect of accounting change
  $ 0.91     $ 0.51     $ 2.07     $ 0.93  
Discontinued operations
                      (0.22 )
Cumulative effect of accounting change
                      0.35  
 
   
 
     
 
     
 
     
 
 
Net Income
  $ 0.91     $ 0.51     $ 2.07     $ 1.06  
 
   
 
     
 
     
 
     
 
 
Diluted Earnings Per Share:
                               
Income before discontinued operations and cumulative effect of accounting change
  $ 0.91     $ 0.50     $ 2.06     $ 0.93  
Discontinued operations
                      (0.22 )
Cumulative effect of accounting change
                      0.34  
 
   
 
     
 
     
 
     
 
 
Net 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 Ended    
    September 30,
  Increase
Sources 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       10  
FES
    515       383       132  
 
   
 
     
 
     
 
 
Total Electric Sales
    3,030       2,963       67  
 
   
 
     
 
     
 
 
Transmission Revenues:
                       
Regulated services
    81       10       71  
Competitive services
    20       16       4  
Gas Sales
    101       111       (10 )
Other Revenues:
                       
EUOC
    92       108       (16 )
FES
    212       197       15  
International
          8       (8 )
Miscellaneous
          10       (10 )
 
   
 
     
 
     
 
 
Total Revenues
  $ 3,536     $ 3,423     $ 113  
 
   
 
     
 
     
 
 

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          Changes in electric generation kilowatt-hour sales and distribution deliveries in the third quarter of 2004 are summarized in the following table:

         
    Increase
Changes 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 Revenue
Increase (Decrease)   (In millions)
Changes in Customer Consumption:
       
Alternative suppliers
  $ (10 )
Economic, weather and other
    (20 )
 
   
 
 
 
    (30 )
 
   
 
 
Changes in Price:
       
Rate changes
    25  
Shopping 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:

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    Three Months Ended
    September 30,
    2004
  2003 (1)
    (In millions)
Sales
  $ 366     $ 264  
Purchases
    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 Ended    
    September 30,
   
                    Increase
Energy Revenue Net of Commodity Costs
  2004
  2003
  (Decrease)
    (In millions)
Electric generation revenue
  $ 1,721     $ 1,603     $ 118  
Fuel and purchased power
    1,285       1,199       86  
 
   
 
     
 
     
 
 
Generation Margin
    436       404       32  
 
   
 
     
 
     
 
 
Gas revenue(1)
    101       104       (3 )
Purchased gas
    97       105       (8 )
 
   
 
     
 
     
 
 
Gas Margin
    4       (1 )     5  
 
   
 
     
 
     
 
 
Total 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

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  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 Ended
Postretirement Benefits Expense(1)
  September 30,
    2004
  2003
    (In millions)
Pension
  $ 21     $ 33  
OPEB
    22       39  
 
   
 
     
 
 
Total
  $ 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 Ended    
    September 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       80  
Wholesale Electric Sales:
                       
EUOC
    387       469       (82 )
FES
    1,422       926       496  
 
   
 
     
 
     
 
 
Total Electric Sales
    8,330       7,961       369  
 
   
 
     
 
     
 
 
Transmission Revenues:
                       
EUOC
    211       20       191  
FES
    57       36       21  
Gas 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:

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    Increase
Changes 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 Revenue
       
Increase (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:

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    Nine Months Ended
    September 30,
    2004
  2003 (1)
    (In millions)
Sales
  $ 1,114     $ 794  
Purchases
    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 Ended    
    September 30,
  Increase
Energy Revenue Net of Commodity Costs
  2004
  2003
  (Decrease)
    (In millions)
Electric generation revenue
  $ 4,745     $ 4,261     $ 484  
Fuel and purchased power
    3,515       3,338       177  
 
   
 
     
 
     
 
 
Generation Margin
    1,230       923       307  
 
   
 
     
 
     
 
 
Gas revenue(1)
    368       467       (99 )
Purchased gas
    353       454       (101 )
 
   
 
     
 
     
 
 
Gas Margin
    15       13       2  
 
   
 
     
 
     
 
 
Total 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;

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  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 Ended
    September 30,
Postretirement Benefits Expense(1)
  2004
  2003
    (In millions)
Pension
  $ 64     $ 91  
OPEB
    68       118  
 
   
 
     
 
 
Total
  $ 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.

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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 Ended
Net Income (Loss)
  September 30,
  September 30,
By Business Segment
  2004
  2003
  2004
  2003
    (In millions)
Regulated services
  $ 315     $ 293     $ 760     $ 856  
Competitive 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 Ended    
    September 30,
   
Regulated Services
  2004
  2003
  Increase
    (In millions)
Total revenues
  $ 1,480     $ 1,478     $ 2  
Net income
    315       293       22  

          The change in operating revenues resulted from the following sources:

                         
    Three Months Ended    
    September 30,
   
                    Increase
Sources of Revenue Changes
  2004
  2003
  (Decrease)
    (In millions)
Electric sales
  $ 1,308     $ 1,360     $ (52 )
Other revenues
    172       118       54  
 
   
 
     
 
     
 
 
Total Revenues
  $ 1,480     $ 1,478     $ 2  
 
   
 
     
 
     
 
 

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\

          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 Ended    
    September 30,
   
Competitive Services
  2004
  2003
  Increase
    (In millions)
Total revenues
  $ 2,064     $ 1,929     $ 135  
Income (loss) before discontinued operations
    47       (88 )     135  
Net income (loss)
    47       (86 )     133  

          The change in total revenues resulted from the following sources:

                         
    Three Months Ended    
    September 30,
   
                    Increase
Sources of Revenue Changes
  2004
  2003
  (Decrease)
    (In millions)
Electric sales
  $ 1,722     $ 1,603     $ 119  
Natural gas sales
    101       111       (10 )
Energy-related sales
    211       205       6  
Other revenues
    30       10       20  
 
   
 
     
 
     
 
 
Total 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

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  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 Ended    
    September 30,
   
                    Increase
Regulated Services
  2004
  2003
  (Decrease)
    (In millions)
Total revenues
  $ 4,047     $ 4,005     $ 42  
Income before cumulative effect of accounting change
    760       754       6  
Net income
    760       856       (96 )

          The change in operating revenues resulted from the following sources:

                         
    Nine Months Ended    
    September 30,
   
                    Increase
Sources of Revenue Changes
  2004
  2003
  (Decrease)
    (In millions)
Electric sales
  $ 3,585     $ 3,700     $ (115 )
Other revenues
    462       305       157  
 
   
 
     
 
     
 
 
Total 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:

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  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 Ended    
    September 30,
   
Competitive Services
  2004
  2003
  Increase
    (In millions)
Total revenues
  $ 5,808     $ 5,412     $ 396  
Income (loss) before discontinued operations and cumulative effect of accounting change
    99       (321 )     420  
Net income (loss)
    99       (324 )     423  
 
   
 
     
 
     
 
 

          The change in total revenues resulted from the following sources:

                         
    Nine Months Ended    
    September 30,
   
                    Increase
Sources of Revenue Changes
  2004
  2003
  (Decrease)
    (In millions)
Electric sales
  $ 4,745     $ 4,261     $ 484  
Natural gas sales
    380       485       (105 )
Energy-related sales
    601       612       (11 )
Other revenues
    82       54       28  
 
   
 
     
 
     
 
 
Total 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:

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  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 Ended
    September 30,
  September 30,
Operating Cash Flows
  2004
  2003
  2004
  2003
    (In millions)
Cash earnings (1)
  $ 745     $ 596     $ 1,634     $ 1,271  
Pension trust contribution
    (500 )           (500 )      
Working capital and other
    320       283       401       34  
 
   
 
     
 
     
 
     
 
 
Total
  $ 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.

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     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 Ended
    September 30,
  September 30,
Securities Issued or Redeemed
  2004
  2003
  2004
  2003
    (In millions)
New Issues
                               
Common stock
  $     $ 935     $     $ 935  
Pollution control notes
    77             261        
Senior secured notes
                550       400  
Long term revolving credit
    10                   40  
Unsecured notes
                150       331  
 
   
 
     
 
     
 
     
 
 
 
  $ 87     $ 935     $ 961     $ 1,706  
Redemptions
                               
First mortgage bonds
  $ 206     $ 302     $ 588     $ 1,002  
Pollution control notes
    80       4       80       54  
Senior secured notes
    374       23       447       282  
Long-term revolving credit
          240       300        
Unsecured notes
    112             337        
Preferred stock
    1       1       1       126  
 
   
 
     
 
     
 
     
 
 
 
  $ 773     $ 570     $ 1,753     $ 1,464  
 
   
 
     
 
     
 
     
 
 
Short-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:

                         
    FirstEnergy        
Unused Borrowing Capability
  Holding Company
  OE
  Total
    (In millions)
Long-Term Revolving Credit
  $ 1,375     $ 375     $ 1,750  
Utilized
    (10 )           (10 )
Letters of Credit
    (151 )           (151 )
 
   
 
     
 
     
 
 
Net
    1,214       375       1,589  
 
   
 
     
 
     
 
 
Short-Term Bank Facilities
          34       34  
Utilized
          (20 )     (20 )
 
   
 
     
 
     
 
 
Net
          14       14  
 
   
 
     
 
     
 
 
Total 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

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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.

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     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   Property            
for Investing Activities
  Additions
  Investments
  Other
  Total
Sources (Uses)           (In millions)        
Three Months Ended September 30, 2004
                               
Regulated Services
  $ (157 )   $ 246 (1)   $ (68 )   $ 21  
Competitive Services
    (47 )     (10 )     (2 )     (59 )
Other
    (7 )     (33 )     83       43  
 
   
 
     
 
     
 
     
 
 
Total
  $ (211 )   $ 203     $ 13     $ 5  
 
   
 
     
 
     
 
     
 
 
Nine Months Ended September 30, 2004
                               
Regulated Services
  $ (377 )   $ 181 (1)(2)   $ (75 )   $ (271 )
Competitive Services
    (152 )     188 (3)     2       38  
Other
    (17 )     20       64       67  
 
   
 
     
 
     
 
     
 
 
Total
  $ (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:

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    Maximum
Guarantees and Other Assurances
  Exposure
    (In millions)
FirstEnergy Guarantees of Subsidiaries:
       
Energy and Energy-Related Contracts (1)
  $ 862  
Other (2)
    149  
 
   
 
 
 
    1,011  
Surety Bonds
    280  
Letters of Credit (3)(4)
    815  
 
   
 
 
Total 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 Paid
   
    Total                   Remaining
Collateral Provisions
  Exposure (1)
  Cash
  Letters of Credit
  Exposure
    (In millions)
Rating downgrade
  $ 358     $ 145     $ 18     $ 195  
Adverse event
    113             23       90  
 
   
 
     
 
     
 
     
 
 
Total
  $ 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

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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:

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Increase (Decrease) in the Fair Value
Of Commodity Derivative Contracts

                                                 
    Three Months Ended   Nine Months Ended
    September 30, 2004
  September 30, 2004
    Non-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     $ 79  
New contract value when entered
                                   
Additions/change in value of existing contracts
          3       3       (5 )     11       6  
Change in techniques/assumptions
                                   
Settled contracts
    1       (4 )     (3 )     1       (16 )     (15 )
 
   
 
     
 
     
 
     
 
     
 
     
 
 
Outstanding net asset at end of period (1)
    63       7       70       63       7       70  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
Non-commodity Net Assets at End of Period:
                                               
Interest Rate Swaps (2)
          27       27             27       27  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
Net Assets — Derivative Contracts at End of Period
  $ 63     $ 34     $ 97     $ 63     $ 34     $ 97  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
Impact 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     $ 12  
Other Liabilities
    (4 )           (4 )
Non-Current-
                       
Other Deferred Charges
    61       31       92  
Other 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     $     $     $ 6  
Other external sources(3)
    9       12       10                   31  
Prices based on models
                      10       23       33  
 
   
 
     
 
     
 
     
 
     
 
     
 
 
Total(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,

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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, 2003
    Notional   Maturity   Fair   Notional   Maturity   Fair
Interest Rate Swaps
  Amount
  Date
  Value
  Amount
  Date
  Value
            (Dollars in millions)                
Fixed to Floating Rate (Fair value hedges)
  $ 200       2006     $ 1     $ 200       2006     $ 1  
 
    100       2008             50       2008        
 
    100       2010       1       100       2010       1  
 
    100       2011       3       100       2011       1  
 
    450       2013       9       350       2013       (1 )
 
    100       2014       3                          
 
    150       2015       (6 )     150       2015       (10 )
 
    200       2016       10                          
 
    150       2018       6       150       2018       1  
 
    50       2019       3       50       2019       1  
 
    100       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:

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  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,   Increase
Regulatory 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             12  
 
   
 
     
 
     
 
 
Total
  $ 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,   Increase
Regulatory Assets By Source
  2004
  2003
  (Decrease)
            (In millions)        
Regulatory transition charge
  $ 5,159     $ 6,427     $ (1,268 )
Customer shopping incentives
    556       371       185  
Customer receivables for future income taxes
    268       340       (72 )
Societal benefits charge
    39       81       (42 )
Loss on reacquired debt
    89       75       14  
Postretirement 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.

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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

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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

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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

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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.

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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

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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

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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

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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

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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

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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.

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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.

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OHIO EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

                                 
    Three Months Ended   Nine Months Ended
    September 30,
  September 30,
    2004
  2003
  2004
  2003
            (In thousands)        
STATEMENTS OF INCOME
                               
OPERATING REVENUES
  $ 766,336     $ 774,714     $ 2,227,978     $ 2,191,165  
 
   
 
     
 
     
 
     
 
 
OPERATING EXPENSES AND TAXES:
                               
Fuel
    15,244       13,978       44,158       37,118  
Purchased power
    242,835       231,619       730,542       691,802  
Nuclear operating costs
    81,244       98,742       235,277       342,319  
Other operating costs
    99,132       106,802       276,289       277,402  
Provision for depreciation and amortization
    108,185       121,734       338,086       335,872  
General taxes
    47,634       46,863       135,688       139,525  
Income taxes
    76,502       66,453       203,863       144,533  
 
   
 
     
 
     
 
     
 
 
Total operating expenses and taxes
    670,776       686,191       1,963,903       1,968,571  
 
   
 
     
 
     
 
     
 
 
OPERATING INCOME
    95,560       88,523       264,075       222,594  
 
OTHER INCOME
    17,141       15,877       50,285       44,789  
 
   
 
     
 
     
 
     
 
 
NET INTEREST CHARGES:
                               
Interest on long-term debt
    10,657       21,241       43,641       70,686  
Allowance 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       15,219  
Subsidiary’s preferred stock dividend requirements
    639       639       1,919       2,463  
 
   
 
     
 
     
 
     
 
 
Net interest charges
    9,986       23,628       48,212       84,196  
 
   
 
     
 
     
 
     
 
 
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE
    102,715       80,772       266,148       183,187  
 
Cumulative effect of accounting change (net of income taxes of $22,389,000) (Note 2)
                      31,720  
 
   
 
     
 
     
 
     
 
 
NET INCOME
    102,715       80,772       266,148       214,907  
 
PREFERRED STOCK DIVIDEND REQUIREMENTS
    623       659       1,843       1,977  
 
   
 
     
 
     
 
     
 
 
EARNINGS ON COMMON STOCK
  $ 102,092     $ 80,113     $ 264,305     $ 212,930  
 
   
 
     
 
     
 
     
 
 
STATEMENTS OF COMPREHENSIVE INCOME
                               
 
NET INCOME
  $ 102,715     $ 80,772     $ 266,148     $ 214,907  
 
OTHER 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 )     19,462  
 
   
 
     
 
     
 
     
 
 
Other comprehensive income (loss)
    (6,913 )     4,156       (2,767 )     (66,614 )
Income tax related to other comprehensive income
    2,850       (1,717 )     1,141       27,471  
 
   
 
     
 
     
 
     
 
 
Other 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.

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OHIO EDISON COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)

                 
    September 30,   December 31,
    2004
  2003
    (In thousands)
ASSETS
               
UTILITY PLANT:
               
In service
  $ 5,376,250     $ 5,269,042  
Less-Accumulated provision for depreciation
    2,683,177       2,578,899  
 
   
 
     
 
 
 
    2,693,073       2,690,143  
 
   
 
     
 
 
Construction work in progress-
               
Electric plant
    181,746       145,380  
Nuclear Fuel
    19,412       554  
 
   
 
     
 
 
 
    201,158       145,934  
 
   
 
     
 
 
 
    2,894,231       2,836,077  
 
   
 
     
 
 
OTHER PROPERTY AND INVESTMENTS:
               
Investment in lease obligation bonds
    370,036       383,510  
Certificates of deposit
          277,763  
Nuclear plant decommissioning trusts
    410,768       376,367  
Long-term notes receivable from associated companies
    208,645       508,594  
Other
    50,298       59,102  
 
   
 
     
 
 
 
    1,039,747       1,605,336  
 
   
 
     
 
 
CURRENT ASSETS:
               
Cash and cash equivalents
    1,279       1,883  
Receivables-
               
Customers (less accumulated provisions of $8,785,000 and $8,747,000, respectively, for uncollectible accounts)
    267,652       280,538  
Associated companies
    469,911       436,991  
Other (less accumulated provisions of $563,000 and $2,282,000, respectively, for uncollectible accounts)
    20,138       28,308  
Notes receivable from associated companies
    635,741       366,501  
Materials and supplies, at average cost
    88,609       79,813  
Prepayments and other
    16,026       14,390  
 
   
 
     
 
 
 
    1,499,356       1,208,424  
 
   
 
     
 
 
DEFERRED CHARGES:
               
Regulatory assets
    1,183,707       1,477,969  
Property taxes
    59,279       59,279  
Unamortized sale and leaseback costs
    61,589       65,631  
Other
    67,207       64,214  
 
   
 
     
 
 
 
    1,371,782       1,667,093  
 
   
 
     
 
 
 
  $ 6,805,116     $ 7,316,930  
 
   
 
     
 
 
CAPITALIZATION AND LIABILITIES
               
CAPITALIZATION:
               
Common stockholder’s equity-
               
Common stock, without par value, authorized 175,000,000 shares - 100 shares outstanding
  $ 2,098,729     $ 2,098,729  
Accumulated other comprehensive loss
    (40,319 )     (38,693 )
Retained earnings
    548,239       522,934  
 
   
 
     
 
 
Total common stockholder’s equity
    2,606,649       2,582,970  
Preferred stock not subject to mandatory redemption
    60,965       60,965  
Preferred stock of consolidated subsidiary not subject to mandatory redemption
    39,105       39,105  
Long-term debt and other long-term obligations
    1,101,179       1,179,789  
 
   
 
     
 
 
 
    3,807,898       3,862,829  
 
   
 
     
 
 
CURRENT LIABILITIES:
               
Currently payable long-term debt
    432,406       466,589  
Short-term borrowings-
               
Associated companies
    22,123       11,334  
Other
    174,010       171,540  
Accounts payable-
               
Associated companies
    291,679       271,262  
Other
    9,467       7,979  
Accrued taxes
    213,427       560,345  
Accrued interest
    21,632       18,714  
Other
    101,138       58,680  
 
   
 
     
 
 
 
    1,265,882       1,566,443  
 
   
 
     
 
 
NONCURRENT LIABILITIES:
               
Accumulated deferred income taxes
    763,283       867,691  
Accumulated deferred investment tax credits
    65,989       75,820  
Asset retirement obligation
    333,644       317,702  
Retirement benefits
    283,548       331,829  
Other
    284,872       294,616  
 
   
 
     
 
 
 
    1,731,336       1,887,658  
 
   
 
     
 
 
COMMITMENTS, 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.

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OHIO EDISON COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

                                 
    Three Months Ended   Nine Months Ended
    September 30,
  September 30,
    2004
  2003
  2004
  2003
            (In thousands)        
CASH FLOWS FROM OPERATING ACTIVITIES:
                               
Net income
  $ 102,715     $ 80,772     $ 266,148     $ 214,907  
Adjustments to reconcile net income to net cash from operating activities–
                               
Provision for depreciation and amortization
    108,185       121,734       338,086       335,872  
Nuclear fuel and lease amortization
    11,914       10,542       33,766       28,411  
Deferred 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 )     4,715  
Deferred lease costs
    33,037       33,977       30,585       31,300  
Prepayments and other current assets
    4,878       3,514       (1,636 )     (6,285 )
Accounts payable
    115,690       (141,910 )     21,905       113,508  
Accrued taxes
    (4,464 )     131,470       (346,918 )     180,604  
Accrued interest
    3,028       (417 )     2,918       (5,523 )
Accrued retirement benefit obligations
    7,253       20,471       24,482       31,652  
Accrued 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       753,000  
 
   
 
     
 
     
 
     
 
 
CASH FLOWS FROM FINANCING ACTIVITIES:
                               
New Financing–
                               
Long-term debt
                30,000       575,000  
Short-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 )     35,752  
 
   
 
     
 
     
 
     
 
 
Net 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       20,512  
 
   
 
     
 
     
 
     
 
 
Cash 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.

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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

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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.

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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 Months
Increase (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 Months
Increase (Decrease)   (In millions)
Fuel
  $ 1     $ 7  
Purchased power costs
    11       39  
Nuclear operating costs
    (17 )     (107 )
Other operating costs
    (8 )     (1 )
 
   
 
     
 
 
Total operation and maintenance expenses
    (13 )     (62 )
Provision for depreciation and amortization
    (13 )     2  
General taxes
    1       (4 )
Income taxes
    10       59  
 
   
 
     
 
 
Total 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.

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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