**GLOSSARY OF
TERMS**





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





ATSI
    American
      Transmission Systems, Inc., owns and operates transmission
      facilitiesAvon
    Avon Energy
      Partners HoldingsCEI
    The Cleveland
      Electric Illuminating Company, an Ohio electric utility operating
      subsidiaryCFC
    Centerior
      Funding Corporation, a wholly owned finance subsidiary of
    CEICompanies
    OE, CEI, TE,
      Penn, JCP&L, Met-Ed and PenelecEmdersa
    Empresa
      Distribuidora Electrica Regional S.A.EUOC
    Electric
      Utility Operating Companies (OE, CEI, TE, Penn, JCP&L, Met-Ed,
      Penelec, and ATSI)FENOC
    FirstEnergy
      Nuclear Operating Company, operates nuclear generating
      facilitiesFES
    FirstEnergy
      Solutions Corp., provides energy-related products and
    servicesFESC
    FirstEnergy
      Service Company, provides legal, financial, and other corporate support
      servicesFGCO
    FirstEnergy
      Generation Corp., operates nonnuclear generating
  facilitiesFirstCom
    First
      Communications, LLC, provides local and long-distance telephone
      serviceFirstEnergy
    FirstEnergy
      Corp., a registered public utility holding companyFSG
    FirstEnergy
      Facilities Services Group, LLC, the parent company of several heating,
      ventilation,
      air
      conditioning and energy management companiesGLEP
    Great Lakes
      Energy Partners, LLC, an oil and natural gas exploration and production
      ventureGPU
    GPU, Inc.,
      former parent of JCP&L, Met-Ed and Penelec, which merged with
      FirstEnergy on
      November 7,
      2001GPU
      Capital
    GPU Capital,
      Inc., owned and operated electric distribution systems in foreign
      countriesGPU
      Power
    GPU Power,
      Inc., owned and operated generation facilities in foreign
      countriesJCP&L
    Jersey
      Central Power & Light Company, a New Jersey electric utility operating
      subsidiaryMARBEL
    MARBEL Energy
      Corporation, previously held FirstEnergy's interest in
  GLEPMet-Ed
    Metropolitan
      Edison Company, a Pennsylvania electric utility operating
      subsidiaryMYR
    MYR Group,
      Inc., a utility infrastructure construction service
  companyNEO
    Northeast
      Ohio Natural Gas Corp., formerly a MARBEL subsidiaryOE
    Ohio Edison
      Company, an Ohio electric utility operating subsidiaryOhio
      Companies
    CEI, OE and
      TEPenelec
    Pennsylvania
      Electric Company, a Pennsylvania electric utility operating
      subsidiaryPenn
    Pennsylvania
      Power Company, a Pennsylvania electric utility operating subsidiary of
      OEPNBV
    PNBV Capital
      Trust, a special purpose entity created by OE in 1996Shippingport
    Shippingport
      Capital Trust, a special purpose entity created by CEI and TE in
      1997TE
    The Toledo
      Edison Company, an Ohio electric utility operating
    subsidiaryTEBSA
    Termobarranquilla
      S.A., Empresa de Servicios PublicosThe following
      abbreviations and acronyms are used to identify frequently used terms in
      this report:ALJ
    Administrative
      Law JudgeAOCL
    Accumulated
      Other Comprehensive LossAPB
    Accounting
      Principles BoardAPB
      25
    APB Opinion
      No. 25, "Accounting for Stock Issued to Employees"APB
      29
    APB Opinion
      No. 29, "Accounting for Nonmonetary Transactions"ARB
      43
    Accounting
      Research Bulletin No. 43, "Restatement and Revision of Accounting
      Research Bulletins"ARO
    Asset
      Retirement ObligationASLB
    Atomic Safety
      and Licensing BoardBGS
    Basic
      Generation ServiceCO2
    Carbon
      DioxideCTC
    Competitive
      Transition ChargeECAR
    East Central
      Area Reliability Coordination AgreementEITF
    Emerging
      Issues Task ForceEITF
      03-1
    EITF Issue
      No. 03-1, "The Meaning of Other-Than-Temporary and Its Application to
      Certain
      Investments”EITF
      03-16
    EITF Issue
      No. 03-16, “Accounting for Investments in Limited Liability
      Companies”EITF
      97-4
    EITF Issue
      No. 97-4 "Deregulation of the Pricing of Electricity - Issues Related to
      the Application of FASB Statements No. 71 and 101"EITF
      99-19
    EITF Issue
      No. 99-19, "Reporting Revenue Gross as a Principal versus Net as an
      Agent"EPA
    Environmental
      Protection Agency









i
 GLOSSARY
OF TERMS, Cont.









FASB
    Financial
      Accounting Standards BoardFERC
    Federal
      Energy Regulatory CommissionFIN
    FASB
      InterpretationFIN
      46R
    FIN 46
      (revised December 2003), "Consolidation of Variable Interest
      Entities"FMB
    First
      Mortgage BondsFSP
    FASB Staff
      PositionFSP EITF
      03-1-1
    FASB Staff
      Position No. EITF Issue 03-1-1, "Effective Date of Paragraphs 10-20 of
      EITF Issue
      No. 03-1,*The
      Meaning of Other-Than-Temporary Impairment and Its Application to Certain
      Investments"*FSP
      106-1
    FASB Staff
      Position No.106-1, "Accounting and Disclosure Requirements Related to the
      Medicare
      Prescription
      Drug, Improvement and Modernization Act of 2003"FSP
      106-2
    FASB Staff
      Position No.106-2, "Accounting and Disclosure Requirements Related to the
      Medicare Prescription Drug,
      Improvementand
      Modernization Act of 2003"FSP
      109-1
    FASB Staff
      Position No. 109-1, "Application of FASB Statement No. 109, Accounting for
      Income Taxes, to the
      Tax Deduction andQualified
      Production Activities provided by the American Jobs Creation Act of
      2004"GAAP
    Accounting
      Principles Generally Accepted in the United StatesHVAC
    Heating,
      Ventilation and Air-conditioningIRS
    Internal
      Revenue ServiceISO
    Independent
      System OperatorKWH
    Kilowatt-hoursLOC
    Letter of
      CreditMACT
    Maximum
      Achievable Control TechnologiesMedicare
      Act
    Medicare
      Prescription Drug, Improvement and Modernization Act of
    2003MISO
    Midwest
      Independent System Transmission Operator, Inc.Moody’s
    Moody’s
      Investors ServiceMTC
    Market
      Transition ChargeMW
    MegawattsNAAQS
    National
      Ambient Air Quality StandardsNERC
    North
      American Electric Reliability CouncilNJBPU
    New Jersey
      Board of Public UtilitiesNOAC
    Northwest
      Ohio Aggregation CoalitionNOV
    Notices of
      ViolationNOX
    Nitrogen
      OxideNRC
    Nuclear
      Regulatory CommissionNUG
    Non-Utility
      GenerationOCC
    Ohio
      Consumers' CounselOCI
    Other
      Comprehensive IncomeOPEB
    Other
      Post-Employment BenefitsPCAOB
    Public
      Company Accounting Oversight Board (United States)PJM
    PJM
      Interconnection L. L. C.PLR
    Provider of
      Last ResortPPUC
    Pennsylvania
      Public Utility CommissionPRP
    Potentially
      Responsible PartyPUCO
    Public
      Utilities Commission of OhioPUHCA
    Public
      Utility Holding Company ActRTC
    Regulatory
      Transition ChargeS&P
    Standard
      & Poor’s Ratings ServiceSBC
    Societal
      Benefits ChargeSEC
    United States
      Securities and Exchange CommissionSFAS
    Statement of
      Financial Accounting StandardsSFAS
      71
    SFAS No. 71,
      "Accounting for the Effects of Certain Types of
  Regulation"SFAS
      87
    SFAS No. 87,
      "Employers' Accounting for Pensions"SFAS
      101
    SFAS No. 101,
      "Accounting for Discontinuation of Application of SFAS
  71"SFAS
      106
    SFAS No. 106,
      "Employers' Accounting for Postretirement Benefits Other Than
      Pensions"SFAS
      115
    SFAS No. 115,
      "Accounting for Certain Investments in Debt and Equity
      Securities"SFAS
      123
    SFAS No. 123,
      "Accounting for Stock-Based Compensation"SFAS
      123(R)
    SFAS No.
      123(R), "Share-Based Payment"SFAS
      131
    SFAS No. 131,
      "Disclosures about Segments of an Enterprise and Related
      Information"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”





ii
 **GLOSSARY OF
TERMS, Cont.**








SFAS
      142
    SFAS No. 142,
      "Goodwill and Other Intangible Assets"SFAS
      143
    SFAS No. 143,
      "Accounting for Asset Retirement Obligations"SFAS
      144
    SFAS No. 144,
      "Accounting for the Impairment or Disposal of Long-Lived
      Assets"SFAS
      150
    SFAS No. 150,
      "Accounting for Certain Financial Instruments with Characteristics of
      BothLiabilities
      and Equity"SFAS
      151
    SFAS No. 151,
      "Inventory costs - an amendment of ARB No. 43, Chapter
  4"SO2
    Sulfur
      DioxideTBC
    Transition
      Bond ChargeTMI-1
    Three Mile
      Island Unit 1TMI-2
    Three Mile
      Island Unit 2VIE
    Variable
      Interest Entity








iii










**MANAGEMENT
REPORTS**





*Management's
Responsibility for Financial Statements*





The consolidated
financial statements were prepared by management who takes responsibility for
their integrity and objectivity. The statements were prepared in conformity with
accounting principles generally accepted in the United States and are consistent
with other financial information appearing elsewhere in this report.
PricewaterhouseCoopers LLP, an independent registered public accounting firm,
has expressed an unqualified opinion on the Company’s 2004 consolidated
financial statements.





FirstEnergy Corp.’s
internal auditors, who are responsible to the Audit Committee of FirstEnergy’s
Board of Directors, review the results and performance of operating units within
the Company for adequacy, effectiveness and reliability of accounting and
reporting systems, as well as managerial and operating controls.





FirstEnergy’s Audit
Committee consists of five independent directors whose duties include:
consideration of the adequacy of the internal controls of the Company and the
objectivity of financial reporting; inquiry into the number, extent, adequacy
and validity of regular and special audits conducted by independent auditors and
the internal auditors; and reporting to the Board of Directors the Committee’s
findings and any recommendation for changes in scope, methods or procedures of
the auditing functions. The Committee is directly responsible for appointing the
Company’s independent registered public accounting firm and is charged with
reviewing and approving all services performed for the Company by the
independent registered public accounting firm and for reviewing and approving
the related fees. The Committee reviews the independent registered public
accounting firm's report on internal quality control and reviews all
relationships between the independent registered public accounting firm and the
Company, in order to assess the independent registered public accounting firm's
independence. The Committee also reviews management’s programs to monitor
compliance with the Company’s policies on business ethics and risk management.
The Committee establishes procedures to receive and respond to complaints
received by the Company regarding accounting, internal accounting controls, or
auditing matters and allows for the confidential, anonymous submission of
concerns by employees. The Audit Committee held six meetings in
2004.





*Management's
Report on Internal Control Over Financial Reporting*





Management is
responsible for establishing and maintaining adequate internal control over
financial reporting as defined in Rule 13a-15(f) of the Securities Exchange Act
of 1934. Using the criteria set forth by the Committee of Sponsoring
Organizations of the Treadway Commission in *Internal
Control - Integrated Framework* , management
conducted an evaluation of the effectiveness of the Company’s internal control
over financial reporting under the supervision of the chief executive officer
and the chief financial officer. Based on that evaluation, management concluded
that the Company’s internal control over financial reporting was effective as of
December 31, 2004 *.* Management’s
assessment of the effectiveness of the Company’s internal control over financial
reporting, as of December 31, 2004, has been audited by
PricewaterhouseCoopers LLP, an independent registered public accounting firm, as
stated in their report which appears on page 2.














1





**Report of
Independent Registered Public Accounting Firm**





To the Stockholders
and Board of Directors of FirstEnergy Corp.:





We have completed an
integrated audit of FirstEnergy Corp.’s 2004 consolidated financial statements
and of its internal control over financial reporting as of December 31, 2004 and
audits of its 2003 and 2002 consolidated financial statements in accordance with
the standards of the Public Company Accounting Oversight Board (United States).
Our opinions, based on our audits, are presented below.





Consolidated
financial statements





In our opinion, the
accompanying consolidated balance sheets and the related consolidated statements
of income, capitalization, common stockholders’ equity, preferred stock, cash
flows and taxes present fairly, in all material respects, the financial position
of FirstEnergy Corp. and its subsidiaries at December 31, 2004 and 2003, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2004 in conformity with accounting principles
generally accepted in the United States of America. These financial statements
are the responsibility of the Company’s management. Our responsibility is to
express an opinion on these financial statements based on our audits. We
conducted our audits of these statements in accordance with the standards of the
Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit of financial statements includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our
opinion.





As discussed in
Note 2(K) to the consolidated financial statements, the Company changed its
method of accounting for asset retirement obligations as of January 1, 2003. As
discussed in Note 7 to the consolidated financial statements, the Company
changed its method of accounting for the consolidation of variable interest
entities as of December 31, 2003.





Internal control
over financial reporting





Also, in our
opinion, management’s assessment, included in the accompanying Management's
Report on Internal Control Over Financial Reporting, that the Company maintained
effective internal control over financial reporting as of December 31, 2004
based on criteria established in *Internal
Control - Integrated Framework* issued by the
Committee of Sponsoring Organizations of the Treadway Commission (COSO), is
fairly stated, in all material respects, based on those criteria. Furthermore,
in our opinion, the Company maintained, in all material respects, effective
internal control over financial reporting as of December 31, 2004, based on
criteria established in *Internal
Control - Integrated Framework* issued by the COSO.
The Company’s management is responsible for maintaining effective internal
control over financial reporting and for its assessment of the effectiveness of
internal control over financial reporting. Our responsibility is to express
opinions on management’s assessment and on the effectiveness of the
Company’s internal control over financial reporting based on our audit. We
conducted our audit of internal control over financial reporting in accordance
with the standards of the Public Company Accounting Oversight Board (United
States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control over financial
reporting was maintained in all material respects. An audit of internal control
over financial reporting includes obtaining an understanding of internal control
over financial reporting, evaluating management’s assessment, testing and
evaluating the design and operating effectiveness of internal control, and
performing such other procedures as we consider necessary in the circumstances.
We believe that our audit provides a reasonable basis for our opinions.





A company’s
internal control over financial reporting is a process designed to provide
reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with
generally accepted accounting principles. A company’s internal control over
financial reporting includes those policies and procedures that (i) pertain
to the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company;
(ii) provide reasonable assurance that transactions are recorded as
necessary to permit preparation of financial statements in accordance with
generally accepted accounting principles, and that receipts and expenditures of
the company are being made only in accordance with authorizations of management
and directors of the company; and (iii) provide reasonable assurance
regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a material effect on the
financial statements.





Because of its
inherent limitations, internal control over financial reporting may not prevent
or detect misstatements. Also, projections of any evaluation of effectiveness to
future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the
policies or procedures may deteriorate.














PricewaterhouseCoopers
LLP


Cleveland,
Ohio


March 7,
2005










2





**FIRSTENERGY
CORP.**





**SELECTED
FINANCIAL DATA**





**For
      the Years Ended December 31,**
    
    **2004**
    
    **2003**
    
    **2002**
    
    **2001**
    
    **2000*****(In
      thousands, except per share amounts)***Revenues
    
    $
    12,453,046
    
    $
    11,674,888
    
    $
    11,453,354
    
    $
    7,237,011
    
    $
    6,470,488Income Before
      Discontinued
      Operations
      and Cumulative Effect of
      Accounting
      Changes
    
    $
    873,779
    
    $
    424,249
    
    $
    618,385
    
    $
    654,946
    
    $
    598,970Net
      Income
    
    $
    878,175
    
    $
    422,764
    
    $
    552,804
    
    $
    646,447
    
    $
    598,970Basic
      Earnings per Share of Common Stock:Before
      Discontinued Operations and
      Cumulative
      Effect of Accounting Changes
    
    $
    2.67
    
    $
    1.40
    
    $
    2.11
    
    $
    2.85
    
    $
    2.69After
      Discontinued Operations and
      Cumulative
      Effect of Accounting Changes
    
    $
    2.68
    
    $
    1.39
    
    $
    1.89
    
    $
    2.82
    
    $
    2.69Diluted
      Earnings per Share of Common Stock:Before
      Discontinued Operations and
      Cumulative
      Effect of Accounting Changes
    
    $
    2.66
    
    $
    1.40
    
    $
    2.10
    
    $
    2.84
    
    $
    2.69After
      Discontinued Operations and
      Cumulative
      Effect of Accounting Changes
    
    $
    2.67
    
    $
    1.39
    
    $
    1.88
    
    $
    2.81
    
    $
    2.69Dividends
      Declared per Share of Common Stock*
    
    $
    1.9125
    
    $
    1.50
    
    $
    1.50
    
    $
    1.50
    
    $
    1.50Total
      Assets
    
    $
    31,067,944
    
    $
    32,909,948
    
    $
    34,386,353
    
    $
    37,351,513
    
    $
    17,941,294Capitalization
      as of December 31:Common
      Stockholders’ Equity
    
    $
    8,589,294
    
    $
    8,289,341
    
    $
    7,050,661
    
    $
    7,398,599
    
    $
    4,653,126Preferred
      Stock:Not Subject
      to Mandatory Redemption
    
    
    335,123
    
    
    335,123
    
    
    335,123
    
    
    480,194
    
    
    648,395Subject to
      Mandatory Redemption
    
    
    --
    
    
    --
    
    
    428,388
    
    
    594,856
    
    
    161,105Long-Term
      Debt and Other Long-TermObligations
    
    
    10,013,349
    
    
    9,789,066
    
    
    10,872,216
    
    
    12,865,352
    
    
    5,742,048Total
      Capitalization
    
    $
    18,937,766
    
    $
    18,413,530
    
    $
    18,686,388
    
    $
    21,339,001
    
    $
    11,204,674





*
    Dividends
      declared in each year include four quarterly dividends of $0.375 per share
      paid in those years. In addition, a quarterly dividend of $0.4125 was
      declared in 2004 payable March 1, 2005, increasing the indicated annual
      dividend rate from $1.50 to $1.65 per
share.








**PRICE RANGE
OF COMMON STOCK**





The Common Stock of
FirstEnergy Corp. is listed on the New York Stock Exchange under the symbol "FE"
and is traded on other registered exchanges.





**2004**
    
    **2003**First Quarter
      High-Low
    
    $
    39.37
    
    $
    35.24
    
    $
    35.19
    
    $
    27.04Second
      Quarter High-Low
    
    $
    39.73
    
    $
    36.73
    
    $
    38.90
    
    $
    30.57Third Quarter
      High-Low
    
    $
    42.23
    
    $
    37.04
    
    $
    38.75
    
    $
    25.82Fourth
      Quarter High-Low
    
    $
    43.41
    
    $
    38.35
    
    $
    35.95
    
    $
    31.66Yearly
      High-Low
    
    $
    43.41
    
    $
    35.24
    
    $
    38.90
    
    $
    25.82





Prices are based on
reports published in The Wall Street
Journal for New York Stock
Exchange Composite Transactions.








**HOLDERS OF
COMMON STOCK**





There were 143,111
and 142,825 holders of 329,836,276 shares of FirstEnergy's Common Stock as of
December 31, 2004 and January 31, 2005, respectively. Information
regarding retained earnings available for payment of cash dividends is given in
Note 10(A) to the consolidated financial statements.





3





**FIRSTENERGY
CORP.**





**MANAGEMENT'S
DISCUSSION AND ANALYSIS OF**


**RESULTS OF
OPERATIONS AND FINANCIAL CONDITION**





*This discussion
includes forward-looking statements based on information currently available to
management. Such statements are subject to certain risks and uncertainties.
These statements typically contain, but are not limited to, the terms
"anticipate," "potential," "expect," "believe," "estimate" and similar words.
Actual results may differ materially due to the speed and nature of increased
competition and deregulation in the electric utility industry, economic or
weather conditions affecting future sales and margins, changes in markets for
energy services, changing energy and commodity market prices, replacement power
costs being higher than anticipated or inadequately hedged, maintenance costs
being higher than anticipated, legislative and regulatory changes (including
revised environmental requirements), adverse regulatory or legal decisions and
outcomes (including revocation of necessary licenses or operating permits, fines
or other enforcement actions and remedies) of governmental investigations and
oversight, including by the Securities and Exchange Commission, the United
States Attorney's Office and the Nuclear Regulatory Commission as disclosed in
our Securities and Exchange Commission filings, generally, and with respect to
the Davis-Besse Nuclear Power Station outage in particular, the availability and
cost of capital, the continuing availability and operation of generating units,
our inability to accomplish or realize anticipated benefits from strategic
goals, our ability to improve electric commodity margins and to experience
growth in the distribution business, our ability to access the public securities
and other capital markets, further investigation into the causes of the
August 14, 2003, regional power outage and the outcome, cost and other
effects of present and potential legal and administrative proceedings and claims
related to the outage,* *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 our Securities and Exchange Commission filings, and other similar
factors. We expressly disclaim any current intention to update any
forward-looking statements contained herein as a result of new information,
future events, or otherwise.*





**EXECUTIVE
SUMMARY**





On a non-GAAP
basis, earnings in 2004 increased to $991 million, or basic earnings of $3.03
per share of common stock, from earnings of $736 million (basic earnings of
$2.42 per share) in 2003 and $889 million (basic earnings of $3.03 per share) in
2002. On a GAAP basis, net income increased to $878 million, or basic earnings
of $2.68 per share in 2004 from $423 million (basic earnings of $1.39 per share)
in 2003 and $553 million (basic earnings of $1.89 per share) in 2002. The
following Non-GAAP Reconciliation displays the unusual items resulting in the
difference between GAAP and non-GAAP earnings.





**Non-GAAP
      Reconciliation**
    
    **2004**
    
    **2003**
    
    **2002****After-tax**
    
    **Basic**
    
    **After-tax**
    
    **Basic**
    
    **After-tax**
    
    **Basic****Amount**
    
    **Earnings**
    
    **Amount**
    
    **Earnings**
    
    **Amount**
    
    **Earnings****(Millions)**
    
    **Per
      Share**
    
    **(Millions)**
    
    **Per
      Share**
    
    **(Millions)**
    
    **Per
      Share****Earnings
      Before Unusual Items (Non-GAAP)**
    
    $
    991
    
    $
    3.03
    
    $
    736
    
    $
    2.42
    
    $
    889
    
    $
    3.03Cumulative
      effect of accounting change
    
    
    
    
    
    
    
    
    102
    
    
    0.33Discontinued
      international operations
    
    
    
    
    
    
    
    
    (101
    )
    
    (0.33
    )
    
    (80
    )
    
    (0.27
    )Non-core
      asset sales/impairments
    
    
    (60
    )
    
    (0.19
    )
    
    (125
    )
    
    (0.41
    )
    
    (62
    )
    
    (0.21
    )Davis-Besse
      impacts
    
    
    (38
    )
    
    (0.12
    )
    
    (170
    )
    
    (0.56
    )
    
    (139
    )
    
    (0.47
    )JCP&L
      disallowance
    
    
    
    
    
    
    
    
    (109
    )
    
    (0.36
    )Litigation
      settlement
    
    
    (11
    )
    
    (0.03
    )Lake plants
      transaction
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (17
    )
    
    (0.06
    )NRG
      settlement
    
    
    
    
    
    
    
    
    99
    
    
    0.33Long-term
      derivative contract adjustment
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (11
    )
    
    (0.04
    )Generation
      project cancellation
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (10
    )
    
    (0.04
    )Other
    
    
    (4
    )
    
    (0.01
    )
    
    (9
    )
    
    (0.03
    )
    
    (17
    )
    
    (0.05
    )**Net
      Income (GAAP)**
    
    $
    878
    
    $
    2.68
    
    $
    423
    
    $
    1.39
    
    $
    553
    
    $
    1.89








The Non-GAAP
measure above, earnings before unusual items, is not calculated in accordance
with GAAP because it excludes the impact of "unusual items." Unusual items
reflect the impact on earnings of events that are not routine, are related to
discontinued businesses or are the cumulative effect of an accounting change. We
believe presenting normalized earnings calculated in this manner provides useful
information to investors in evaluating the ongoing results of our businesses and
assists investors in comparing our operating performance to the operating
performance of others in the energy sector.





4





Under our debt
paydown and refinancing program, we retired, refinanced, or restructured more
than $2.8 billion in long-term debt during the year. These financing activities
contributed to the $143 million decrease in interest charges in
2004.





Sales for 2004 were
up over the previous year, driven primarily by strong sales in the wholesale
power market. This increase is largely reflective of a stronger economy and the
return of the Davis-Besse Nuclear Power Station to active status. Despite milder
weather experienced over much of our service area in 2004, our generating fleet
produced a record 76 billion KWH. Our fossil fleet produced 46 billion KWH and
our nuclear fleet produced a record 30 billion KWH.





The Company made a
voluntary $500 million contribution to its pension plan in order to help add
security to future plan benefits. The net after-tax cost of the contribution was
approximately $300 million. This contribution is expected to reduce our overall
risk profile, because it reduces uncertainty regarding the plan’s unfunded
liability.





We continue to
participate in meaningful settlement negotiations with the parties to the New
Source Review case involving our W. H. Sammis Plant (see Environmental Matters).
As a result, the U.S. District Court judge hearing the case has delayed without
rescheduling the remedy phase of the trial, originally scheduled to begin in
January 2005.





In November 2004,
t he
Board of Directors increased our indicated annual dividend to $1.65 per share,
payable quarterly at a rate of $0.4125 per share. This action represents a 10%
increase over the previous quarterly rate and is the first dividend increase
since FirstEnergy was formed in 1997. The Board also adopted a dividend policy
that will target sustainable annual dividend increases after 2005 that generally
reflect an annual growth rate within the range of 4% to 5%, and an earnings
payout ratio generally within the range of 50% to 60%.





At the end of
December 2004, accrued dividends of approximately $135 million were included in
other current liabilities on the accompanying consolidated balance sheet.
Dividends declared in 2004 were $1.9125 which included quarterly dividends of
$0.375 per share paid in each quarter of 2004 and a dividend of $0.4125 payable
in the first quarter of 2005. The amount and timing of all dividend declarations
are subject to the discretion of the Board and its consideration of business
conditions, results of operations, financial condition and other
factors.





**FIRSTENERGY’S
BUSINESS**





FirstEnergy is a
registered public utility holding company headquartered in Akron, Ohio that
provides regulated and competitive energy services (see Results of Operations -
Business Segments). Our eight EUOC provide transmission and distribution
services and comprise the nation’s fifth largest investor-owned electric system
- based on serving 4.4 million customers within 36,100 square miles of Ohio,
Pennsylvania and New Jersey. ATSI provides transmission services to our Ohio
Companies and Penn. The service areas of our EUOC are highlighted
below.








**Operating
      Company**
    **Area
      Served**
    **Customers
      Served**OE
    Central and
      northeastern Ohio
    1,031,066Penn
    Western
      Pennsylvania
    157,411CEI
    Northeastern
      Ohio
    757,889TE
    Northwestern
      Ohio
    311,225JCP&L
    Northern,
      western and east
      central New
      Jersey
    1,061,764Met-Ed
    Eastern
      Pennsylvania
    526,380Penelec
    Western
      Pennsylvania
    588,066ATSI
    Service areas
      of OE, Penn,
      CEI and
      TE








Competitive energy
services are principally provided by FES. FSG and MYR provide heating,
ventilation, air-conditioning, refrigeration, process piping, plumbing,
electrical and facility control systems and high-efficiency electrotechnologies.
While competitive revenues have increased since 2001, regulated energy services
continue to provide the majority of our revenues and earnings.








5





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 generation services while the EUOC provide regulated
transmission and distribution services. FGCO, a wholly owned subsidiary of FES,
leases and operates fossil and hydroelectric plants owned by the Ohio Companies
and Penn. 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 power supply requirements for the Ohio Companies and Penn are provided
through FES.





FirstEnergy
acquired international assets in the merger with GPU in November 2001. GPU
Capital and its subsidiaries had 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, all of the international operations had
been divested because those assets were inconsistent with our vision for
FirstEnergy.





**STRATEGY**





We continue to
pursue our goal of being the leading regional supplier of energy and related
services in the northeast quadrant of the United States, where we see the best
opportunities for growth. Our fundamental business strategy remains stable and
unchanged. While we continue to build a strong regional presence, key elements
for our strategy are in place and management's focus continues to be on
execution. We intend 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 our core
business.





Our current focus
includes: (1) minimizing unplanned extended generation outages; (2) enhancing
our system reliability; (3) optimizing our generation portfolio; (4) effectively
managing commodity supplies and risks; (5) preserving and enhancing appropriate
margins; (6) enhancing our credit profile and financial flexibility; and (7)
managing the skills and diversity of our workforce.





**RISKS**





We face a number of
industry and enterprise risks and challenges, including:





·
    Changes in
      commodity prices, which could adversely affect our
  margins;·
    Complex and
      changing government regulations, which could have a negative impact on
      results of operations;·
    Costs of
      compliance with environmental laws, which are significant, and the cost of
      compliance with future environmental
      laws,
      which could adversely affect cash flow and
  profitability;·
    Financial
      performance risks related to the economic cycles of the electric utility
      industry;·
    The
      continuing availability and operation of generating units, which is
      dependent on retaining the necessary licenses,permits, and
      operatingauthority
      from governmental entities, including the NRC;·
    Risks of
      nuclear generation, including uncertainties relating to health and safety,
      additional capital costs, the adequacy of insurance
      coverageand nuclear
      plant decommissioning;·
    Operational
      risks arising from the reliability of our power plants and transmission
      and distribution equipment;·
    Regulatory
      changes in the electric industry, which could affect our competitive
      position and result in unrecoverable costs adversely
      affecting ourbusiness and
      results of operations;·
    Human
      resource risks associated with the availability of trained and qualified
      labor to meet our future staffing requirements;·
    Weather
      conditions such as tornadoes, hurricanes, storms and droughts, as well as
      seasonal temperature variations;·
    A downgrade
      in credit ratings, which could negatively affect our ability to access
      capital; and·
    We may
      ultimately incur liability in connection with federal proceedings
      described in Note 13 to the consolidated
      financial
      statements.








6





**RECLASSIFICATIONS**





As discussed in
Notes 1 and 14 to the consolidated financial statements, certain prior year
amounts have been reclassified to conform to the current year presentation.
Revenues related to transmission activities previously recorded as wholesale
electric sales revenues were reclassified as transmission revenues. Expenses
(including transmission and congestion charges) were reclassified among
purchased power, other operating costs and amortization of regulatory assets to
conform to the current year presentation of generation commodity costs. As
further discussed in Note 14 to the consolidated financial statements, segment
reporting in 2003 and 2002 was reclassified to conform to the 2004 business
segment organizations and operations. These reclassifications did not change
previously reported earnings in 2003 and 2002.





**RESULTS OF
OPERATIONS**





The 2004 increase
in net income of $455 million from the prior year resulted from several factors.
First, the number of unusual charges incurred in 2004 decreased as certain
initiatives began to reach their conclusion in 2003 and early 2004. Second,
adverse operating results at FSG led to impairment of its goodwill in 2003. Its
remaining goodwill and certain other assets were further impaired in 2004 as we
prepared to sell the FSG operations. Finally, a positive turn in the economy,
moderation in the rate at which alternative suppliers expanded their presence in
our franchise areas, and reduced expenses enhanced 2004 financial results.
Moderating those positive results was the absence in 2004 of the NRG settlement
gain recorded in 2003 and the cumulative effect of an accounting change which
offset some of the negative 2003 factors described above.





The $130 million
decrease in net income in 2003 compared with 2002 reflected many of the factors
described above. Additional costs were being incurred during the extended outage
at Davis-Besse for replacement power, accelerated maintenance, extended-scope
enhancements to plant design and human performance and safety issues. Also,
losses were being recorded on international operations, alternative suppliers
were expanding more rapidly in our franchise areas, the economy negatively
influenced financial results and we recorded our first impairment of goodwill.
In 2003, the NRG settlement gain and cumulative effect of an accounting change
offset the negative factors.





The financial
results in 2004, 2003 and 2002 are summarized in the table below.








**FirstEnergy**
    
    **2004**
    
    **2003**
    
    **2002*****(In
      millions, except per share amounts****)*Total
      revenues
    
    $
    12,453
    
    $
    11,675
    
    $
    11,453Income before
      discontinued operations
      and
      cumulative effect of accounting change
    
    
    874
    
    
    424
    
    
    618Discontinued
      operations
    
    
    4
    
    
    (103
    )
    
    (65
    )Cumulative
      effect of accounting change
    
    
    --
    
    
    102
    
    
    --Net
      Income
    
    $
    878
    
    $
    423
    
    $
    553Basic
      Earnings Per Share:Income before
      discontinued operations and
      cumulative
      effect of accounting change
    
    $
    2.67
    
    $
    1.40
    
    $
    2.11Discontinued
      operations
    
    
    0.01
    
    
    (0.34
    )
    
    (0.22
    )Cumulative
      effect of accounting change
    
    
    --
    
    
    0.33
    
    
    --Net
      Income
    
    $
    2.68
    
    $
    1.39
    
    $
    1.89Diluted
      Earnings Per Share:Income before
      discontinued operations and
      cumulative
      effect of accounting change
    
    $
    2.66
    
    $
    1.40
    
    $
    2.10Discontinued
      operations
    
    
    0.01
    
    
    (0.34
    )
    
    (0.22
    )Cumulative
      effect of accounting change
    
    
    --
    
    
    0.33
    
    
    --Net
      Income
    
    $
    2.67
    
    $
    1.39
    
    $
    1.88








7





*Results of
Operations - 2004 Compared With 2003*





Sources of changes
in total revenues are summarized in the following table:





**Increase****Sources
      of Revenue Changes**
    
    **2004**
    
    **2003**
    
    **(Decrease)*****(In
      millions*****)**Retail
      Electric Sales:EUOC - Wires
    
    $
    4,701
    
    $
    4,787
    
    $
    (86
    )- Generation
    
    
    3,158
    
    
    3,139
    
    
    19FES
    
    
    637
    
    
    566
    
    
    71Wholesale
      Electric Sales:EUOC
    
    
    512
    
    
    570
    
    
    (58
    )FES
    
    
    1,823
    
    
    1,143
    
    
    680Total
      Electric Sales
    
    
    10,831
    
    
    10,205
    
    
    626Transmission
      Revenues:EUOC
    
    
    333
    
    
    23
    
    
    310FES
    
    
    39
    
    
    59
    
    
    (20
    )Other
      Revenues:EUOC
    
    
    361
    
    
    443
    
    
    (82
    )FES -
      Generation
    
    
    35
    
    
    10
    
    
    25FSG
    
    
    398
    
    
    327
    
    
    71International
    
    
    --
    
    
    25
    
    
    (25
    )Miscellaneous
    
    
    456
    
    
    583
    
    
    (127
    )Total
      Revenues
    
    $
    12,453
    
    $
    11,675
    
    $
    778








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





**Increase****Changes
      in KWH Sales**
    
    **(Decrease)**Electric
      Generation Sales:Retail:EUOC
    
    
    (1.5
    )%FES
    
    
    4.9
    %Wholesale
    
    
    26.7
    %Total
      Electric Generation Sales
    
    
    7.7
    %EUOC
      Distribution Deliveries:Residential
    
    
    2.0
    %Commercial
    
    
    2.6
    %Industrial
    
    
    0.6
    %Total
      Distribution Deliveries
    
    
    1.6
    %








Retail sales by our
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 $67 million decrease in retail electric revenues from our
EUOC in 2004.








**Sources
      of the Changes in EUOC Retail Electric Revenue*****(In
      millions*****)****Increase
      (Decrease)**Changes in
      Customer Consumption:Alternative
      suppliers
    
    $
    (77
    )Economy,
      weather and other
    
    
    10932Changes in
      Price:Rate
      changes
    
    
    (19
    )Shopping
      incentives
    
    
    (51
    )Rate mix and
      other
    
    
    (29
    )(99
    )Net
      Decrease
    
    $
    (67
    )








8





Lower prices were
partially offset by increased energy use due to a strengthening economy.
Although the demand for energy increased in all three customer groups -
residential, commercial and industrial - milder weather in 2004 moderated the
energy needs of residential and commercial customers. Customers shopping
in our franchise areas for alternative energy suppliers remained a major factor
contributing to lower EUOC revenues with alternative suppliers providing a
larger portion of franchise customer energy requirements.





Alternative
suppliers provided 24.3% of the total energy delivered to retail customers in
our franchise areas in 2004, compared to 21.8% in 2003. Lower prices resulted
from three factors - a shopping credit
rate increase, a change in the mix of sales with fewer retail customers
receiving EUOC 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.





Additional credits
provided to customers (primarily under the Ohio transition plan) to promote
customer shopping for alternative suppliers reduced regulated retail electric
sales revenues. Reductions from shopping incentives are deferred for future
recovery under our Ohio transition plan and do not affect current period
earnings.





Electric sales by
FES increased by $751 million primarily from additional sales to the wholesale
market that increased $680 million in 2004. Higher electric sales to the
wholesale market were possible due in part to a 13% increase in generation
resulting from record production from our generating fleet. Retail sales
increased $71 million, with nearly half of the revenue increase from customers
within our franchise areas switching to FES.





The gross
generation margin in 2004 improved by $402 million compared to 2003, with
electric generation revenue increasing more rapidly than the costs of fuel and
purchased power. Excluding the unusual charge resulting from the July 2003
JCP&L rate decision, the gross generation margin improved by $249 million
and the ratio of gross generation margin to revenue increased from 26.1% to
27.1%, primarily reflecting additional lower-cost nuclear generation, offset in
part by higher purchased power prices.








**Gross
      Generation Margin**
    
    **2004**
    
    **2003**
    
    **Increase*****(In
      millions)***Electric
      generation revenue
    
    $
    6,130
    
    $
    5,418
    
    $
    712Fuel and
      purchased power costs
    
    
    4,469
    
    
    4,159
    
    
    310Gross
      Generation Margin
    
    $
    1,661
    
    $
    1,259
    
    $
    402





Income before
discontinued operations and the cumulative effect of an accounting change
increased $450 million in 2004. In addition to the impact of improved gross
generation margin discussed above, the following factors contributed to the
change in earnings:





·
    Lower nuclear
      expenses of $169 million primarily as a result of one scheduled refueling
      outage at Beaver Valley
      Unit 1 in
      2004 compared to three scheduled refueling outages in 2003 (Beaver Valley
      Unit 1, Beaver Valley Unit 2
      and Perry)
      and reduced incremental maintenance costs at the Davis-Besse Nuclear Power
      Station related to its restart;·
    Lower energy
      delivery expenses of $94 million due to reduced storm restoration costs in
      2004, a higher level of
      construction
      activities in 2004 compared to a higher level of maintenance activities in
      the prior year and
      additional
      distribution reliability expenses incurred in the third quarter of
      2003;·
    Reduced
      fossil generation expenses of $49 million due to less maintenance in 2004
      compared to the prior year;·
    A net $51
      million decrease in employee benefits expense primarily as a result of
      reduced postretirement benefit plan
      expenses (see
      Postretirement Plans below), offset in part by higher incentive
      compensation and severance costs;·
    Lower
      interest charges of $143 million primarily due to debt and preferred stock
      redemption and refinancing activities and
      pollution
      control note repricings;·
    A net $81
      million reduction in goodwill impairment charges for FSG with $36 million
      (see Note 2(H)) and $117 million
      recognized in
      2004 and 2003, respectively; and·
    Additional
      deferrals of regulatory assets of $63 million, due principally to Ohio
      shopping incentives.








9





Partially
offsetting the above sources of improved earnings were five factors:








·
    Reduced
      revenues of $86 million from distribution deliveries due to lower
      prices;·
    Increased
      amortization of regulatory assets of $87 million primarily from additional
      Ohio transition plan amortization
      and a change
      in amortization resulting from the July 2003 JCP&L rate
      decision;·
    The absence
      in 2004 of the 2003 earnings benefit of $168 million realized from the
      settlement of our claim against
      NRG for the
      terminated sale of four fossil plants;·
    An aggregate
      increase in Ohio property tax expense and other state taxes of $40
      million; and·
    Increased
      income taxes of $263 million primarily reflecting higher taxable
      earnings.





*Results of
Operations - 2003 Compared With 2002*





Sources of changes
in total revenues are summarized in the following table:








**Increase****Sources
      of Revenue Changes**
    
    **2003**
    
    **2002**
    
    **(Decrease)*****(In
      millions*****)**Retail
      Electric Sales:EUOC - Wires
    
    $
    4,787
    
    $
    4,872
    
    $
    (85
    )- Generation
    
    
    3,139
    
    
    3,357
    
    
    (218
    )FES
    
    
    566
    
    
    348
    
    
    218Wholesale
      Electric Sales:EUOC
    
    
    570
    
    
    511
    
    
    59FES
    
    
    1,143
    
    
    568
    
    
    575Total
      Electric Sales
    
    
    10,205
    
    
    9,656
    
    
    549Transmission
      Revenues:EUOC
    
    
    23
    
    
    39
    
    
    (16
    )FES
    
    
    59
    
    
    2
    
    
    57Other
      Revenues:EUOC
    
    
    443
    
    
    387
    
    
    56FES -
      Generation
    
    
    10
    
    
    39
    
    
    (29
    )FSG
    
    
    327
    
    
    383
    
    
    (56
    )International
    
    
    25
    
    
    294
    
    
    (269
    )Miscellaneous
    
    
    583
    
    
    653
    
    
    (70
    )Total
      Revenues
    
    $
    11,675
    
    $
    11,453
    
    $
    222








Changes in electric
generation sales and distribution deliveries in 2003 are summarized in the
following table:








**Increase****Changes
      in KWH Sales**
    
    **(Decrease****)**Electric
      Generation Sales:Retail:EUOC
    
    
    (7.2
    )%FES
    
    
    53.0
    %Wholesale
    
    
    40.2
    %Total
      Electric Generation Sales
    
    
    8.3
    %EUOC
      Distribution Deliveries:Residential
    
    
    (0.7
    )%Commercial
    
    
    1.2
    %Industrial
    
    
    (0.4
    )%Total
      Distribution Deliveries
    
    
    --
    %











10





Retail sales by our
EUOC contributed more than 70% of electric revenues and over 60% of total
revenues. The following major factors contributed to the $303 million decrease
in retail electric revenues from our EUOC in 2003:








**Sources
      of the Changes in EUOC Retail Electric Revenue****Increase
      (Decrease)**
    
    ***(In
      millions*****)**Changes in
      Customer Consumption:Alternative
      suppliers
    
    $
    (295
    )Economy,
      weather and other
    
    
    (16
    )(311
    )Changes in
      Price:Rate
      changes
    
    
    (11
    )Shopping
      incentives
    
    
    (6
    )Rate mix and
      other
    
    
    258Net
      Decrease
    
    $
    (303
    )








The lower retail
electric revenues resulted principally from increased sales by alternative
suppliers in our franchise areas. Alternative suppliers provided 21.8% of the
total energy delivered to retail customers in our franchise areas in 2003,
compared to 15.7% in 2002. As a result, generation kilowatt-hour sales to retail
customers of our regulated services were 7.2% lower. Additional credits provided
to customers (primarily under the Ohio transition plan) to promote customer
shopping for alternative suppliers further reduced regulated retail electric
sales revenues. Reductions from shopping incentives are deferred for future
recovery under our Ohio transition plan and do not materially affect current
period earnings. The NJBPU decision in July 2003 that lowered JCP&L's base
electric rates effective August 1, 2003 contributed to lower
rates.





Electric sales by
FES increased by $793 million primarily from additional sales to the wholesale
market that increased $575 million in 2003 on a 75% increase in kilowatt-hour
sales. A majority of the increase was due to sales by our competitive electric
energy services segment for a portion of New Jersey's BGS requirements and sales
in the spot market. Retail sales by FES increased by $218 million as a result of
a 53% increase in kilowatt-hour sales. That increase primarily resulted from
retail customers within our Ohio franchise areas switching to FES under Ohio's
electricity choice program and from growth in competitive retail sales outside
our franchise areas.





The gross
generation margin in 2003 declined by $215 million compared to the same period
in 2002. Excluding the unusual charge of $153 million of power costs that were
disallowed in the July 2003 JCP&L rate decision referred to above, our gross
generation margin decreased $62 million and the ratio of gross generation margin
to revenue decreased from 30.8% to 26.1%. Higher electric generation sales
resulted principally from the additional sales in the wholesale market and were
more than offset by increased fuel and purchased power costs. Purchased power
costs increased by $879 million due to higher unit costs and additional
quantities purchased. Increased volumes were required to supply obligations
assumed by FES for BGS sales in New Jersey, as well as other wholesale
commitments, and additional supplies were required to replace reduced nuclear
generation (down 14%). Reduced nuclear generation output resulted from
additional refueling outage work performed at the Perry and Beaver Valley plants
in 2003 and the Davis-Besse extended outage.








**Increase****Gross
      Generation Margin**
    
    **2003**
    
    **2002**
    
    **(Decrease)*****(In
      millions)***Electric
      generation revenue
    
    $
    5,418
    
    $
    4,784
    
    $
    634Fuel and
      purchased power costs
    
    
    4,159
    
    
    3,310
    
    
    849Gross
      Generation Margin
    
    $
    1,259
    
    $
    1,474
    
    $
    (215
    )








Income before
discontinued operations and the cumulative effect of an accounting change
decreased $194 million in 2003. In addition to the impact of reduced gross
generation margin and lower revenues from distribution deliveries discussed
above, the following factors contributed to the decrease in
earnings:





·
    Asset
      impairment charges of $56 million incurred in 2003 including a $26 million
      non-cash charge related to the
      divestiture
      of our interest in TEBSA; a $13 million impairment on the monetization of
      the note received from the
      sale of our
      79.9% interest in Avon; an additional $5 million impairment upon the
      divestiture of our remaining
      interest in
      Avon; and $12 million related to the disposition of NEO and the write down
      of our investment
      in Pantellos,
      an internet business-to-business marketplace serving the utility
      sector;





11








·
    A non-cash
      goodwill impairment charge of $117 million recorded in the third quarter
      of 2003 reducing the carrying value
      of
      FSG;·
    Increased
      energy delivery costs of $36 million principally due to storm restoration
      expenses and an accelerated
      reliability
      program within JCP&L's service territory;·
    Higher
      nuclear expenses of $54 million as a result of an additional scheduled
      nuclear refueling outage in 2003
      and unplanned
      work performed during the scheduled refueling outages at the Perry Plant
      and Beaver Valley Unit 1.
      The higher
      production costs were partially offset by lower maintenance costs at the
      Davis-Besse Nuclear Power Station;·
    Planned
      maintenance outages at three of our fossil generating plants during the
      fourth quarter of 2003 increased
      non-nuclear
      operating expenses by approximately $25 million;·
    Increased
      postretirement plan expenses (see Postretirement Plans below) offset in
      part by lower incentive compensation
      costs
      contributed to a net cost increase of $94 million;·
    Revenues less
      operating expenses for energy-related services declined $17 million due to
      general declines associated
      with economic
      conditions;·
    An estimated
      environmental liability of $15 million was recognized in the fourth
      quarter of 2003; and·
    Increased
      amortization of regulatory assets of $138 million due principally to
      additional Ohio transition plan amortization
      and a July
      2003 JCP&L rate case disallowance.Partially
      offsetting these higher costs were five factors:·
    A settlement
      of our claim against NRG for the terminated sale of four fossil plants
      resulted in a $168 million gain;·
    Reduced
      depreciation resulting from several factors -- lower charges resulting
      from the implementation of
      SFAS 143 ($61
      million), revised service life assumptions for nuclear generating plants
      ($28 million) and reduced
      depreciation
      rates resulting from the JCP&L rate case ($18
  million);·
    Lower
      interest charges of $146 million primarily due to debt and preferred stock
      redemption and refinancing activities
      and pollution
      control note repricings;·
    The absence
      of unusual charges recognized in 2002 resulted in a further net reduction
      of other operating expenses
      ($181
      million) in 2003; and·
    Reduced
      income taxes of $106 million primarily reflecting lower taxable
      earnings.





*Cumulative
Effect of Accounting Change*





Results in 2003
included an after-tax credit to net income of $102 million recorded upon the
adoption of SFAS 143 in January 2003 (see discussion below). We identified
applicable legal obligations as defined under the new standard for nuclear power
plant decommissioning, reclamation of a sludge disposal pond at the Bruce
Mansfield Plant and two coal ash disposal sites. 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, we had recorded decommissioning liabilities of $1.24 billion.  We
expect substantially all of our nuclear decommissioning costs for Met-Ed,
Penelec, JCP&L and Penn to be recoverable in rates over time. Therefore, we
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
existing decommissioning 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. The application of
SFAS 143 (excluding the cumulative adjustment described above) resulted in the
following changes to expense categories and net income in 2003:








12








**Increase****Effect
      of SFAS 143**
    
    **(Decrease)*****(In
      millions)***Other
      operating expense:Cost of
      removal expenditures (previously included
      in
      depreciation)
    
    $
    10Depreciation:Elimination
      of decommissioning expense
    
    
    (89
    )Depreciation
      of asset retirement cost
    
    
    2Accretion of
      asset retirement liability
    
    
    42Elimination
      of removal cost component
    
    
    (16
    )Net decrease
      to depreciation
    
    
    (61
    )Income
      taxes
    
    
    21Net income
      effect
    
    $
    30








**DISCONTINUED
OPERATIONS**





Discontinued
operations for 2004, 2003 and 2002 include FES’ natural gas business (see Note
2(J)) which management expects to sell within one year. In 2003 and 2002,
discontinued operations were reflected for Emdersa and EGSA, as we substantially
completed our exit from foreign operations acquired through the merger with GPU
in 2001. In addition, the results for the FSG subsidiaries, Colonial Mechanical,
Webb Technologies and Ancoma, Inc. and the MARBEL subsidiary, NEO, which were
divested in 2003, have been reported as discontinued operations for the years
2003 and 2002. The following table summarizes the sources of income (losses)
from discontinued operations:








**Discontinued
      Operations (Net of tax)**
    
    **2004**
    
    **2003**
    
    **2002*****(In
      millions)***Emdersa -
      abandonment
    
    $
    --
    
    $
    (67
    )
    $
    --EGSA - loss
      on sale
    
    
    --
    
    
    (33
    )
    
    --Ancoma - loss
      on sale
    
    
    --
    
    
    (3
    )
    
    --Total
      losses
    
    
    --
    
    
    (103
    )
    
    --Reclassification
      of operating income (loss)
      to
      discontinued operations:FES’ natural
      gas business
    
    
    4
    
    
    (2
    )
    
    15Emdersa,
      EGSA, Colonial, Webb, Ancoma and NEO
    
    
    --
    
    
    2
    
    
    (80
    )Total
    
    $
    4
    
    $
    (103
    )
    $
    (65
    )








**POSTRETIREMENT
PLANS**





Strengthened equity
markets (reducing pension costs), as well as amendments to our health care
benefits plan in the first quarter of 2004 and the Medicare Act signed by
President Bush in December 2003 (reducing OPEB costs) combined to reduce
postretirement benefits expenses by $109 million in 2004 from the prior year. A
$191 million increase in benefits expenses in 2003 from 2002 resulted from
declines in equity markets in 2001 and 2002 and a reduction in our assumed
discount rate in 2002 which increased pension expenses. Also, higher health care
payments and a related increase in projected trend rates led to higher OPEB
expenses in 2003. The following table reflects the portion of postretirement
costs that were charged to expense in 2004, 2003 and 2002.








**Postretirement
      Expenses (Income)**
    
    **2004**
    
    **2003**
    
    **2002*****(In
      millions)***Pension
    
    $
    83
    
    $
    123
    
    $
    (14
    )OPEB
    
    
    87
    
    
    156
    
    
    102Total
    
    $
    170
    
    $
    279
    
    $
    88








13





Pension and OPEB
expenses are included in various cost categories and have contributed to cost
decreases in 2004, discussed above. The $500 million voluntary contribution made
in 2004 is expected to result in a reduction in pension costs in 2005, 2006 and
2007 compared to the level they would have been without the voluntary
contribution. Including the effect of higher interest costs resulting from
funding the voluntary contribution, earnings per share are expected to benefit
by approximately $0.06 in each of the next three years. See "Critical Accounting
Policies - Pension and Other Postretirement Benefits Accounting" for a
discussion of the impact of underlying assumptions on postretirement
expenses.





**SUPPLY
PLAN**





Our affiliates are
obligated to provide generation service with an estimated power supply of 99.5
billion KWH for 2005. These obligations arise from customers who have elected to
continue to receive generation service from our EUOCs under regulated retail
rate tariffs and from customers who have selected FES as their alternate
generation provider. Geographically, approximately 63% of the total generation
service obligation is for customers located in the MISO market area and 37% for
customers located in the PJM market area. Included in the PJM market area are
obligations of FES to provide power to electric distribution companies in the
state of New Jersey, including JCP&L. FES incurred this obligation as a
successful bidder in the State of New Jersey’s auction of BGS.





Within the
franchise territories of the EUOC, alternative energy suppliers currently
provide generation service for approximately 1,800 MW (summer peak) of load with
an estimated energy requirement of eight billion KWH. If these alternate
suppliers fail to deliver power to their customers located in the EUOC’s service
areas, the EUOC must procure replacement power in the role of PLR (see Note 2(D)
for discussion of the auction of JCP&L's PLR obligation). JCP&L's costs
for any replacement power would be recovered under the applicable state
regulatory rules.





To meet these
generation service obligations, our affiliates own and operate 13,387 MW of
installed generating capacity, which for 2005 is expected to provide
approximately 75% of the required power supply. The balance has been secured
through a mix of long-term purchases (term of contract greater than one year)
and short-term purchases (term of contract less than one year). Changes in power
supply requirements will be met through spot market transactions.





**PJM
INTERCONNECTION TRANSACTIONS**





FES engages in
purchase and sale transactions in the PJM Market (see Note 2 (D)) to support the
supply of end-use customers, including its BGS obligation in New Jersey and PLR
requirements in Pennsylvania. FES meets its supply commitments by transmitting
energy into the PJM control area and through bilateral purchased power contracts
with counterparties in PJM. FES schedules purchase and sale transactions for
each hour in PJM on a day-ahead basis with system balancing occurring real-time.
FES sells energy to the PJM Market at the location of its supply (transmitted
and contracted energy) and purchases energy from the PJM Market at the location
of its demand (end-use customer load).





FES accounts for
energy transactions in the PJM Market in accordance with EITF 99-19, recognizing
purchases and sales on a gross basis by recording each discrete transaction (see
Note 2(D)). This presentation may not be comparable to other energy companies
that have dedicated generating capacity in ISOs or fail to meet the criteria for
gross presentation in EITF 99-19.





**RESULTS OF
OPERATIONS - BUSINESS SEGMENTS**





We have three
reportable segments: regulated services, competitive electric energy services
and facilities (HVAC) services. The aggregate “Other” segments do not
individually meet the criteria to be considered a reportable segment. “Other”
consists of international businesses that have subsequently been divested, MYR
(a construction service company); natural gas operations and telecommunications
services. The assets and revenues for the other business operations are below
the quantifiable threshold for operating segments for separate disclosure as
“reportable segments.” 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 electric energy services business segment
primarily consists of the subsidiaries (FES, FGCO and FENOC) that sell
electricity in deregulated markets and operate the generation facilities of OE,
CEI, TE and Penn resulting from the deregulation of the Companies' electric
generation business (see Note 2(A) - Accounting for the Effects of
Regulation).





The regulated
services segment designs, constructs, operates and maintains our regulated
transmission and distribution systems. Its revenues are primarily derived from
electricity delivery and transition costs recovery. The regulated services
segment assets include generating units that are leased to the competitive
electric energy services. Its internal revenues represent the rental revenues
for the generating unit leases.








14





The competitive
electric energy services segment has responsibility for our generation
operations as discussed under Note 2(A) to the consolidated financial
statements. Its net income is primarily derived from revenues from all electric
generation sales consisting of generation services to regulated franchise
customers who have not chosen an alternative generation supplier, retail sales
in deregulated markets and all domestic unregulated electricity sales in the
retail and wholesale markets and the related costs of electricity generation and
sourcing of commodity requirements. Its net income also reflects the expense of
the intersegment generating unit leases discussed above and property tax amounts
related to those generating units.





Segment reporting
for 2003 and 2002 was reclassified to conform with the current year business
segment organization and operations emphasizing our regulated electric
businesses and competitive electric energy operations. A previous reportable
segment was the more expansive competitive services segment whose aggregate
operations consisted of our generation operations, natural gas commodity sales,
providing local and long-distance phone service and other competitive energy
related businesses such as facilities services and construction service (MYR)
which was viewed as offering a comprehensive menu of energy related services.
Management's focus is now on our core electric business. This has resulted in a
change in performance review analysis from an aggregate view of all competitive
services operations to a focus on its competitive electric energy operations.
During our periodic review of reportable segments under SFAS 131, that change
resulted in the revision of reportable segments to the separate reporting of
competitive electric energy operations, facilities services and including all
other competitive services operations in the "Other" segment. Facilities
services is being disclosed as a reporting segment due to the subsidiaries
qualifying as held for sale (see Note 2 (J)). In addition, certain amounts
(including transmission and congestion charges) were reclassified among
purchased power, other operating costs and depreciation and amortization to
conform with the current year presentation of generation commodity costs.
Interest expense on holding company debt and corporate support services revenues
and expenses are now included in "Reconciling Items" and "Other" includes those
operating segment results discussed above.





Financial results
discussed below include revenues and expenses from transactions among our
business segments. A reconciliation of segment financial results to consolidated
financial results is provided in Note 14 to the consolidated financial
statements. Net income (loss) by business segment was as follows:








**Net
      Income (Loss)****By
      Business Segment**
    
    **2004**
    
    **2003**
    
    **2002*****(In
      millions)***Segments:Regulated
      services
    
    $
    1,015
    
    $
    1,164
    
    $
    962Competitive
      electric energy services
    
    
    104
    
    
    (320
    )
    
    (170
    )Facilities
      services
    
    
    (36
    )
    
    (81
    )
    
    3Other
    
    
    45
    
    
    (160
    )
    
    (47
    )Reconciling
      items*
    
    
    (250
    )
    
    (180
    )
    
    (195
    )Total
    
    $
    878
    
    $
    423
    
    $
    553





*  Includes interest
expense on holding company debt, corporate support services revenues and
expenses and other reconciling
items.








*Regulated
Services - 2004 versus 2003*





Financial results
of the regulated services segment were as follows:








**Increase****Regulated
      Services**
    
    **2004**
    
    **2003**
    
    **(Decrease)*****(In
      millions)***Total
      revenues
    
    $
    5,713
    
    $
    5,572
    
    $
    141Income before
      cumulative effect of accounting change
    
    
    1,015
    
    
    1,063
    
    
    (48
    )Net
      income
    
    
    1,015
    
    
    1,164
    
    
    (149
    )











15





The change in
operating revenues resulted from the following sources:





**Increase****Sources
      of Revenue Changes**
    
    **2004**
    
    **2003**
    
    **(Decrease)*****(In
      millions)***Electric
      sales
    
    $
    4,701
    
    $
    4,787
    
    $
    (86
    )Other
      revenues:External
      sales
    
    
    694
    
    
    466
    
    
    228Internal
      sales
    
    
    318
    
    
    319
    
    
    (1
    )Total
      Revenues
    
    $
    5,713
    
    $
    5,572
    
    $
    141








The net increase in
operating revenues resulted from:





·
    A decrease of
      $86 million in retail sales - a $60 million reduction in revenues from
      distribution deliveries and a
      $26 million
      increase in the credits for shopping incentives to customers;
      and·
    A $228
      million increase in other revenues primarily due to higher transmission
      revenues and, to a lesser extent,
      earnings
      recognized on decommissioning trust investments (see Note 5 -
      Investments).





Income before
discontinued operations and the cumulative effect of an accounting change
decreased $48 million. In addition to the above changes in revenue, the
following factors contributed to the change:





·
    The absence
      in 2004 of the earnings benefit of the 2003 settlement of our claim
      against NRG for the terminated sale
      of four
      fossil plants, which resulted in a $168 million gain;·
    An aggregate
      increase in Ohio property tax expense and other state taxes of $32
      million; and·
    Additional
      MISO and PJM transmission costs of $238 million related to the
      transmission component of other
      revenue
      discussed above.





Partially
offsetting those factors were:





·
    Lower energy
      delivery expenses (net of refunds to third-party suppliers) of $71 million
      due to reduced storm
      restoration
      costs in 2004, a higher level of construction activities in 2004 compared
      to a higher level of maintenance
      activities in
      the prior year and distribution reliability expenses incurred in the third
      quarter of 2003;·
    Lower
      interest charges of $130 million primarily related to debt and preferred
      stock redemption and refinancing activities
      and pollution
      control note repricings; and·
    Reduced
      income taxes of $38 million primarily reflecting reduced taxable
      earnings.





*Regulated
Services - 2003 versus 2002*





Financial results
for regulated services were as follows:








**Increase****Regulated
      Services**
    **2003**
    **2002**
    **(Decrease)*****(In
      millions)***Total
      revenues
    $5,572
    $5,616
    $
      (44)Income before
      cumulative effect of accountingChange
    1,063
    962
    101Net
      income
    1,164
    962
    202








16





The change in
operating revenues resulted from the following sources:








**Increase****Sources
      of Revenue Changes**
    
    **2003**
    
    **2002**
    
    **(Decrease)*****(In
      millions)***Electric
      sales
    
    $
    4,787
    
    $
    4,872
    
    $
    (85
    )Other
      revenues:External
      sales
    
    
    466
    
    
    426
    
    
    40Internal
      sales
    
    
    319
    
    
    318
    
    
    1Total
      Revenues
    
    $
    5,572
    
    $
    5,616
    
    $
    (44
    )





The net decrease in
operating revenues resulted from:





·
    A decrease of
      $85 million in retail sales - a $40 million reduction in revenues from
      distribution deliveries and a $45 million
      increase in
      the credits for shopping incentives to customers; and·
    A net $40
      million increase in other revenues due in part to JCP&L TBC revenue
      and jobbing and contracting revenue.





Income before
discontinued operations and the cumulative effect of an accounting change
increased $101 million. The following factors offset the lower revenues and
contributed to the net increase in income:





·
    Settlement of
      our claim against NRG for the terminated sale of four fossil plants which
      resulted in our recording a
      $168 million
      pre-tax credit to earnings;·
    Lower
      interest charges of $95 million primarily related to debt and preferred
      stock redemption and refinancing activities
      and pollution
      control note repricings; and·
    The absence
      of unusual charges recognized in 2002 of $6
million.





Partially
offsetting the above sources of improved earnings were four
factors:





·
    Increased
      energy delivery costs of $41 million principally due to storm restoration
      expenses and an accelerated
      reliability
      program within JCP&L’s service territory;·
    A net
      increase in depreciation and amortization expense of $9 million resulting
      from additional amortization of regulatory
      assets offset
      in part by reduced depreciation;·
    Additional
      MISO and PJM transmission costs of $29 million related to the transmission
      component of other revenue; and·
    Increased
      income taxes of $57 million primarily reflecting higher taxable
      earnings.








*Competitive
Electric Energy Services - 2004 versus 2003*





Financial results
for competitive electric energy services were as follows:








**Competitive
      Electric Energy Services**
    **2004**
    **2003**
    **Increase*****(In
      millions)***Total
      revenues
    $6,204
    $5,487
    $717Net income
      (loss)
    104
    (320)
    424








The change in total
revenues resulted from the following sources :











**Sources
      of Revenue Changes**
    **2004**
    **2003**
    **Increase*****(In
      millions)***Electric
      sales
    $6,130
    $5,418
    $712Other
      revenues
    74
    69
    5Total
      Revenues
    $6,204
    $5,487
    $717






17


The net increase in
electric sales resulted from:





·
    Higher retail
      generation sales from customer choice programs ($71 million) and EUOC
      regulated customers
      ($19
      million); and·
    Increased FES
      wholesale revenues of $680 million offset in part by a $58 million
      decrease in sales to EUOC
      wholesale
      customers.








The gross
generation margin increased $402 million as electric generation revenues
increased at a greater rate than the related costs of fuel and purchased power.
Higher electric generation revenues resulted from increased sales to both retail
and wholesale customers. Excluding the impact of the July 2003 JCP&L rate
decision, the gross generation margin increased $249 million, reflecting the
benefit of increased sales and the availability of additional lower-cost nuclear
generation.





Net income
increased $424 million. In addition to the improved gross generation margin
discussed above, the following factors contributed to the increase in
earnings:





·
    Lower nuclear
      expenses of $169 million primarily as a result of one scheduled refueling
      outage at Beaver
      Valley Unit 1
      in 2004 compared to three scheduled refueling outages in 2003 (Beaver
      Valley Unit 1, Beaver
      Valley Unit 2
      and Perry) and reduced incremental maintenance costs at the Davis-Besse
      Nuclear Power
      Station
      related to its restart; and·
    Reduced
      fossil generation expenses of $49 million due to less maintenance in 2004
      compared to the
      prior
      year.








Partially
offsetting the above sources of improved earnings were increased income taxes of
$294 million reflecting higher taxable earnings.





*Competitive
Electric Energy Services - 2003 versus 2002*





Financial results
for competitive electric energy services were as follows:








**Competitive
      Electric Energy Services**
    
    **2003**
    
    **2002**
    
    **Increase*****(In
      millions)***Total
      revenues
    
    $
    5,487
    
    $
    4,825
    
    $
    662Net
      loss
    
    
    320
    
    
    170
    
    
    150








The change in total
revenues resulted from the following sources:








**Sources
      of Revenue Changes**
    
    **2003**
    
    **2002**
    
    **Increase*****(In
      millions)***Electric
      sales
    
    $
    5,418
    
    $
    4,784
    
    $
    634Other
      revenues
    
    
    69
    
    
    41
    
    
    28$
    5,487
    
    $
    4,825
    
    $
    662








The net increase in
electric sales resulted from increased FES wholesale revenues of $575 million
and increased sales to EUOC wholesale customers of $59 million.





The gross
generation margin decreased $215 million as fuel and purchased power costs
increased more rapidly than related electric generation revenue. Excluding the
unusual charge from the July 2003 JCP&L rate decision, the gross generation
margin decreased $62 million, reflecting higher fuel and purchased power costs.
Purchased power costs increased due to higher unit costs and additional
quantities purchased. Increased volumes were required to supply obligations
assumed and to replace reduced nuclear generation.





18





In addition to the
reduced gross generation margin discussed above, the following factors
contributed to the increase in the net loss:





·
    Higher
      nuclear expenses of $54 million as a result of an additional scheduled
      nuclear refueling outage in 2003
      and unplanned
      work performed during the scheduled refueling outages at the Perry Plant
      and Beaver Valley Unit 1.
      The higher
      production costs were partially offset by lower maintenance costs at the
      Davis-Besse Nuclear Power
      Station;
      and·
    Planned
      maintenance outages at three of our fossil generating plants during the
      fourth quarter of 2003
      increased
      non-nuclear operating expenses by approximately $25
    million.





Partially
offsetting the above sources of lower earnings were reduced income taxes of $134
million reflecting lower taxable income.





*Facilities
Services - 2004 versus 2003*





Financial results
for facilities services were as follows:





**Increase****Facilities
      Services**
    
    **2004**
    
    **2003**
    
    **(Decrease)*****(In
      millions)***Total
      revenues
    
    $
    398
    
    $
    327
    
    $
    71Net
      loss
    
    
    36
    
    
    81
    
    
    (45
    )




Revenue increased
$71 million or 22% in 2004 compared to 2003 reflecting stronger market
conditions. Losses  from FSG goodwill
impairment dominated financial results in 2004 and 2003 resulting in non-cash,
pre-tax charges to earnings of $36 million and $117 million, respectively (see
Note 2 (H)). The impairment in 2003 was identified during our annual assessment
of goodwill and in 2004 from an analysis performed at year-end when a firm
decision was made to divest all FSG assets. Excluding the after-tax impact of
the goodwill impairments FSG experienced net income in 2004 of $1 million,
following a $255,000 loss in 2003.





*Facilities
Services - 2003 versus 2002*





Financial results
for facilities services were as follows:








**Facilities
      Services**
    **2003**
    **2002**
    **(Decrease)*****(In
      millions)***Total
      revenues
    $327
    $383
    $(56)Net income
      (loss)
    (81)
    3
    (84)








Revenues decreased
$56 million or 15% in 2003 primarily reflecting depressed market conditions and
reduced customer maintenance services due to mild weather. The loss in 2003
resulted principally from the effect of the $117 million pre-tax charge
(discussed above). Excluding the effect of the goodwill impairment, after-tax
earnings decreased $3 million in 2003 compared to 2002.





**CAPITAL
RESOURCES AND LIQUIDITY**





Our cash
requirements in 2004 for operating expenses, construction expenditures,
scheduled debt maturities and preferred stock redemptions were met without
increasing our net debt and preferred stock outstanding. During 2005, we expect
to meet our contractual obligations primarily with cash from operations.
Thereafter, we expect 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 through
revolving credit facilities. In 2004, FirstEnergy received $782 million of
cash dividends on common stock from its subsidiaries and paid $491 million in
cash dividends on common stock to its shareholders. There are no material
restrictions on the payments of cash dividends by our subsidiaries.





As of
December 31, 2004, we had $53 million of cash and cash equivalents,
compared with $114 million as of December 31, 2003. Cash and cash
equivalents as of December 31, 2003 included $32 million received in
December 2003 from the NRG settlement claim sold in January 2004. The major
sources for changes in these balances are summarized below.





19





*Cash Flows From
Operating Activities*





Our consolidated
net cash from operating activities is provided primarily by our regulated and
competitive electric energy businesses (see Results of Operations - Business Segments
above). Net cash provided from operating activities was $1.877 billion in 2004,
$1.755 billion in 2003 and $1.932 billion in 2002, summarized as follows:





**Operating
      Cash Flows**
    **2004**
    **2003**
    **2002*****(In
      millions)*****Increase
      (Decrease)**Cash earnings(1)
    $2,168
    $1,825
    $1,640Pension trust
      contribution(2)
    (300)
    --
    --Working
      capital and other
    9
    (70)
    292Total
    $1,877
    $1,755
    $1,932





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


(2)  Pension trust
contribution net of $200 million of income tax benefits.





Cash earnings (in
the table above) is not a measure of performance calculated in accordance with
GAAP. We believe that cash earnings is a useful financial measure because it
provides investors and management with an additional means of evaluating our
cash-based operating performance. The following table reconciles cash earnings
with net income.








**Reconciliation
      of Cash Earnings**
    
    **2004**
    
    **2003**
    
    **2002*****(In
      millions)***Net Income
      (GAAP)
    
    $
    878
    
    $
    423
    
    $
    553Non-Cash
      Charges (Credits):Provision for
      depreciation
    
    
    590
    
    
    607
    
    
    722Amortization
      of regulatory assets
    
    
    1,166
    
    
    1,079
    
    
    941Deferral of
      new regulatory assets
    
    
    (257
    )
    
    (194
    )
    
    (184
    )Nuclear fuel
      and lease amortization
    
    
    96
    
    
    66
    
    
    81Deferred
      costs recoverable as regulatory assets
    
    
    (417
    )
    
    (427
    )
    
    (544
    )Deferred
      income taxes*
    
    
    58
    
    
    54
    
    
    77Goodwill
      impairment
    
    
    36
    
    
    117
    
    
    --Disallowed
      regulatory assets
    
    
    --
    
    
    153
    
    
    --Cumulative
      effect of accounting change
    
    
    --
    
    
    (175
    )
    
    --Other
      non-cash expenses
    
    
    18
    
    
    122
    
    
    (6
    )Cash Earnings
      (Non-GAAP)
    
    $
    2,168
    
    $
    1,825
    
    $
    1,640





*  Excludes $200
million of deferred tax benefit from pension contribution in 2004.





Net cash provided
from operating activities increased $122 million in 2004 compared to 2003 due to
a $343 million increase in cash earnings as described under "Results of
Operations" and a $79 million increase from changes in working capital,
partially offset by a $300 million after-tax voluntary pension trust
contribution. The working capital increase resulted in part from changes of $88
million in receivables, $78 million in prepayments and other current assets, $59
million in payables and a $53 million NUG power contract restructuring
transaction, partially offset by a $237 million decrease in accrued tax
balances. Net cash provided from operating activities decreased $177 million in
2003 compared to 2002 due to a $362 million decrease in working capital
partially offset by a $185 million increase in cash earnings, as described above
under "Results of Operations." The working capital decrease primarily resulted
from changes of $388 million in payables and $165 million in prepayments and
other current assets, partially offset by a $196 million increase in accrued tax
balances.





*Cash Flows From
Financing Activities*





In 2004, 2003 and
2002, net cash used for financing activities of $1.457 billion, $1.298 billion
and $1.138 billion, respectively, primarily reflected the redemptions of debt
and preferred stock shown below. The following table provides details regarding
new issues and redemptions during 2004, 2003 and 2002:





20








**Securities
      Issued or Redeemed**
    
    **2004**
    
    **2003**
    
    **2002*****(In
      millions)****New
      Issues*Common
      stock
    
    $
    --
    
    $
    934
    
    $
    --Pollution
      control notes
    
    
    261
    
    
    --
    
    
    158Senior
      secured notes
    
    
    300
    
    
    400
    
    
    370Unsecured
      notes
    
    
    400
    
    
    627
    
    
    140$
    961
    
    $
    1,961
    
    $
    668*Redemptions*First
      mortgage bonds
    
    $
    589
    
    $
    1,483
    
    $
    728Pollution
      control notes
    
    
    80
    
    
    238
    
    
    93Senior
      secured notes
    
    
    471
    
    
    323
    
    
    278Long-term
      revolving credit
    
    
    95
    
    
    85
    
    
    --Unsecured
      notes
    
    
    337
    
    
    --
    
    
    210Preferred
      stock
    
    
    2
    
    
    127
    
    
    522$
    1,574
    
    $
    2,256
    
    $
    1,831Short-term
      borrowings, net
    
    $
    (351
    )
    $
    (575
    )
    $
    479








Net cash used for
financing activities increased by $159 million in 2004 from 2003. The increase
resulted primarily from the absence of a $934 million common equity financing in
2003 and a $37 million increase in common stock dividends partially offset by an
$840 million decrease in net redemption of preferred securities and debt. Net
cash used for financing activities in 2003 increased $160 million from 2002. The
increase in cash used for financing activities resulted primarily from an
increase in net redemptions of debt and preferred securities of $1.1 billion
partially offset by the common equity financing in 2003.





We had
approximately $170 million of short-term indebtedness at the end of 2004
compared to approximately $522 million at the end of 2003. Available borrowing
capability as of December 31, 2004 included the following:








**Borrowing
      Capability**
    
    **FirstEnergy**
    
    **OE**
    
    **Total*****(In
      millions)***Long-term
      revolving credit
    
    $
    1,375
    
    $
    375
    
    $
    1,750Utilized
    
    
    (215
    )
    
    --
    
    
    (215
    )Letters of
      credit
    
    
    (135
    )
    
    --
    
    
    (135
    )Net
    
    
    1,025
    
    
    375
    
    
    1,400Short-term
      bank facilities
    
    
    --
    
    
    34
    
    
    34Utilized
    
    
    --
    
    
    (21
    )
    
    (21
    )Net
    
    
    --
    
    
    13
    
    
    13Total Unused
      Borrowing Capability
    
    $
    1,025
    
    $
    388
    
    $
    1,413





At the end of 2004,
the Ohio Companies and Penn had the aggregate capability to issue approximately
$4.4 billion of additional FMB on the basis of property additions and retired
bonds under the terms of their respective mortgage indentures. The issuance of
FMB by OE 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 FMB) (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 $641 million and $588 million, respectively, as of December 31, 2004.
Under the provisions of its senior note indenture, JCP&L may issue
additional FMB only as collateral for senior notes. As of December 31,
2004, JCP&L had the capability to issue $644 million of additional senior
notes upon the basis of FMB collateral. Based upon applicable earnings coverage
tests in their respective charters, OE, Penn, TE and JCP&L could issue a
total of $4.5 billion of preferred stock (assuming no additional debt was
issued) as of the end of 2004. CEI, Met-Ed and Penelec have no restrictions on
the issuance of preferred stock (see Note 10(C) - Long-Term Debt and Other
Long-Term Obligations for a discussion of debt covenants).





As of
December 31, 2004, approximately $1.0 billion remained under FirstEnergy's
shelf registration statement, filed with the SEC in 2003, to support future
securities issues. The shelf registration provides the flexibility to issue and
sell various types of securities, including common stock, debt securities, and
share purchase contracts and related share purchase units.





At the end of 2004
and 2003, our common equity as a percentage of capitalization stood at 45%
compared to 38% at the end of 2002. The higher common equity percentage in 2004
and 2003 compared to 2002 reflects net redemptions of preferred stock and
long-term debt, and the increase in retained earnings.





21





Our 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 our
syndicated $375 million three-year facility 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, our 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 our short-term working capital requirements and those
of our subsidiaries. Total unused borrowing capability under existing facilities
and accounts receivable financing facilities totaled $1.7 billion as of
December 31, 2004.





Borrowings under
these facilities are conditioned on 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. As of
December 31, 2004, FirstEnergy’s and OE’s fixed charge coverage ratios, as
defined under the credit agreements, were 4.48 to 1 and 7.15 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. FirstEnergy and
OE are in compliance with these financial covenants. 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, condition (financial or otherwise),
results of operations, or prospects.





Neither
FirstEnergy's nor OE’s primary credit facilities contain any provisions that
either restrict their ability to borrow or accelerate repayment of outstanding
advances as a result of any change in their credit ratings. Each primary
facility does contain “pricing grids”, whereby the cost of funds borrowed under
the facility is related to the credit ratings of the company borrowing the
funds.





Our regulated
companies have the ability to borrow from each other and the holding company to
meet their short-term working capital requirements. A similar but separate
arrangement exists among our unregulated companies. FESC administers these two
money pools and tracks surplus funds of FirstEnergy and the respective regulated
and unregulated 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
unregulated companies, available bank borrowings include only FirstEnergy’s
$1.375 billion of revolving credit facilities. Companies receiving a loan under
the money pool agreements must repay the principal amount of the 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 2004 was 1.43% for the regulated
companies’ money pool and 1.55% for the unregulated companies' money
pool.





Our access to
capital markets and costs of financing are influenced by the ratings of our
securities. The following table shows our securities ratings as of
December 31, 2004. The ratings outlook from the ratings agencies on all
securities is stable.





22








**Ratings
      of Securities****Securities**
    **S&P**
    **Moody’s**
    **Fitch****FirstEnergy**
    Senior
      unsecured
    BB+
    Baa3
    BBB-**OE**
    Senior
      secured
    BBB
    Baa1
    BBB+Senior
      unsecured
    BB+
    Baa2
    BBBPreferred
      stock
    BB
    Ba1
    BBB-**CEI**
    Senior
      secured
    BBB-
    Baa2
    BBB-Senior
      unsecured
    BB+
    Baa3
    BBPreferred
      stock
    BB
    Ba2
    BB-**TE**
    Senior
      secured
    BBB-
    Baa2
    BBB-Senior
      unsecured
    BB+
    Baa3
    BBPreferred
      stock
    BB
    Ba2
    BB-**Penn**
    Senior
      secured
    BBB
    Baa1
    BBB+Senior
      unsecured(1)
    BB+
    Baa2
    BBBPreferred
      stock
    BB
    Ba1
    BBB-**JCP&L**
    Senior
      secured
    BBB+
    Baa1
    BBB+Preferred
      stock
    BB
    Ba1
    BBB**Met-Ed**
    Senior
      secured
    BBB
    Baa1
    BBB+Senior
      unsecured
    BBB-
    Baa2
    BBB**Penelec**
    Senior
      secured
    BBB
    Baa1
    BBB+Senior
      unsecured
    BBB-
    Baa2
    BBB


(1)  Penn's only senior
unsecured debt obligations are notes underlying pollution control revenue
refunding bonds issued by the Ohio


Air Quality Development Authority to
which bonds this rating applies.





On December 10,
2004, S&P reaffirmed our ‘BBB-' corporate credit rating and kept the outlook
stable. S&P noted that the stable outlook reflects our improving financial
profile and cash flow certainty through 2006. S&P stated that should the two
refueling outages at the Davis-Besse and Perry nuclear plants scheduled for the
first quarter of 2005 be completed successfully without any significant negative
findings and delays, our outlook would be revised to positive. S&P also
stated that a ratings upgrade in the next several months did not seem likely, as
remaining issues of concern to S&P, primarily the outcome of environmental
litigation and SEC investigations, are not likely to be resolved in the short
term.





*Cash Flows From
Investing Activities*





Net cash flows used
in investing activities resulted principally from property additions. Regulated
services expenditures for property additions primarily include expenditures
supporting the distribution of electricity. Capital expenditures by the
competitive electric energy services segment are principally generation-related.
The following table summarizes 2004 investments by our regulated services and
competitive services segments:





23








**Summary
      of Cash Flows**
    
    **Property****Used
      for Investing Activities**
    
    **Additions**
    
    **Investments**
    
    **Other**
    
    **Total****2004
      Sources (Uses)**
    
    ***(In
      millions)***Regulated
      services
    
    $
    (572
    )
    $
    181
    
    $
    (88
    )
    $
    (479
    )Competitive
      electric energy services
    
    
    (246
    )
    
    16
    
    
    (2
    )
    
    (232
    )Facilities
      services
    
    
    (3
    )
    
    --
    
    
    2
    
    
    (1
    )Other
    
    
    (4
    )
    
    184
    
    
    (6
    )
    
    174Reconciling
      items
    
    
    (21
    )
    
    (22
    )
    
    100
    
    
    57Total
    
    $
    (846
    )
    $
    359
    
    $
    6
    
    $
    (481
    )**2003
      Sources (Uses)**Regulated
      services
    
    $
    (434
    )
    $
    105
    
    $
    16
    
    $
    (313
    )Competitive
      electric energy services
    
    
    (335
    )
    
    (32
    )
    
    8
    
    
    (359
    )Facilities
      services
    
    
    (4
    )
    
    61
    
    
    (70
    )
    
    (13
    )Other
    
    
    (9
    )
    
    46
    
    
    116
    
    
    153Reconciling
      items
    
    
    (74
    )
    
    28
    
    
    9
    
    
    (37
    )Total
    
    $
    (856
    )
    $
    208
    
    $
    79
    
    $
    (569
    )**2002
      Sources (Uses)**Regulated
      services
    
    $
    (490
    )
    $
    27
    
    $
    2
    
    $
    (461
    )Competitive
      electric energy services
    
    
    (391
    )
    
    --
    
    
    (25
    )
    
    (416
    )Facilities
      services
    
    
    (6
    )
    
    --
    
    
    --
    
    
    (6
    )Other
    
    
    (9
    )
    
    96
    
    
    43
    
    
    130Reconciling
      items
    
    
    (102
    )
    
    (40
    )
    
    62
    
    
    (80
    )Total
    
    $
    (998
    )
    $
    83
    
    $
    82
    
    $
    (833
    )





Net cash used for
investing activities in 2004 decreased by $88 million from 2003. The decrease
was primarily due to $278 million in cash proceeds from certificates of deposit
received in the third quarter of 2004 partially offset by a $117 million
change in NUG trust activity. Net cash used for investing activities in 2003
decreased by $264 million from 2002. The decrease was primarily due to a $142
million decrease in property additions and a $174 million increase in cash
payments on long-term notes receivable.





Our capital
spending for the period 2005-2007 is expected to be about $3.3 billion
(excluding nuclear fuel), of which $979 million applies to 2005. Investments for
additional nuclear fuel during the 2005-2007 period are estimated to be
approximately $268 million, of which about $53 million applies to 2005. During
the same period, our nuclear fuel investments are expected to be reduced by
approximately $280 million and $90 million, respectively, as the nuclear fuel is
consumed.





**CONTRACTUAL
OBLIGATIONS**





*Contractual
Obligations*





As of December 31,
2004, our estimated cash payments under existing contractual obligations that we
consider firm obligations are as follows:





**2006-**
    
    **2008-****Contractual
      Obligations**
    
    **Total**
    
    **2005**
    
    **2007**
    
    **2009**
    
    **Thereafter*****(In
      millions)***Long-term
      debt(5)
    
    $
    10,890
    
    $
    710
    
    $
    1,565
    
    $
    622
    
    $
    7,993Short-term
      borrowings
    
    
    170
    
    
    170
    
    
    --
    
    
    --
    
    
    --Preferred
      stock(1)
    
    
    17
    
    
    2
    
    
    14
    
    
    1
    
    
    --Capital
      leases (2)
    
    
    19
    
    
    5
    
    
    6
    
    
    2
    
    
    6Operating
      leases(2)
    
    
    2,362
    
    
    183
    
    
    349
    
    
    376
    
    
    1,454Pension
      funding (3)
    
    
    --
    
    
    --
    
    
    --
    
    
    --Fuel and
      purchased power(4)
    
    
    13,765
    
    
    2,464
    
    
    4,184
    
    
    3,148
    
    
    3,969Total
    
    $
    27,223
    
    $
    3,534
    
    $
    6,118
    
    $
    4,149
    
    $
    13,422








(1)
    Subject to mandatory redemption.
(2)
    See
      Note 6 to the consolidated financial
statements.
(3)
    We
      estimate that no further pension contributions will be required through
      2009 to maintain our defined benefit pension plan's funding
      at
      a minimum
      required level as determined by government regulations. We are unable to
      estimate projected contributions beyond 2009.
      See 
      Note 3 to the consolidated financial
statements.
(4)
    Amounts under contract with fixed or minimum quantities and approximate
      timing.
(5)
    Amounts reflected do not include interest or long-term
debt

























24





*Guarantees and
Other Assurances*





As part of normal
business activities, we enter into various agreements on behalf of our
subsidiaries to provide financial or performance assurances to third parties.
Such agreements include contract guarantees, surety bonds, and LOCs. Some of the
guaranteed contracts contain ratings contingent collateralization
provisions.





As of
December 31, 2004, our maximum exposure to potential future payments under
outstanding guarantees and other assurances totaled approximately $2.4 billion,
as summarized below:





**Maximum****Guarantees
      and Other Assurances**
    
    **Exposure*****(In
      millions)***FirstEnergy
      Guarantees of SubsidiariesEnergy and
      Energy-Related Contracts (1)
    
    $
    878Other
      (2)
    
    
    1491,027Surety
      Bonds
    
    
    279LOC
      (3)(4)
    
    
    1,098Total
      Guarantees and Other Assurances
    
    $
    2,404





(1)
    Issued
      for a one-year term, with a 10-day termination right by
      FirstEnergy.


(2)
    Issued
      for various terms.


(3)
    Includes $135 million issued for various terms under LOC capacity
      available in FirstEnergy’s revolving credit
      agreement and $299 million outstanding in support of pollution
      control revenue bonds issued with various
maturities.


(4)
    Includes approximately $216 million pledged in connection with the sale
      and leaseback of Beaver Valley
      Unit 2
      by CEI and TE, $294 million pledged in connection with the sale and
      leaseback of Beaver Valley Unit 2 by
      OE and
      $154 million pledged in connection with the sale and leaseback of Perry
      Unit 1 by OE.








We guarantee energy
and energy-related payments of our subsidiaries involved in energy commodity
activities - principally to facilitate normal physical transactions involving
electricity, gas, emission allowances and coal. We also provide guarantees to
various providers of subsidiary financing principally for the acquisition of
property, plant and equipment. These agreements legally obligate us to fulfill
the obligations of our subsidiaries directly involved in these 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, our guarantee enables
the counterparty's legal claim to be satisfied by our other assets. The
likelihood that such parental guarantees will increase amounts otherwise paid by
us to meet our obligations incurred in connection with ongoing energy and
energy-related contracts is remote.





While these types
of guarantees are normally parental commitments for the future payment of
subsidiary obligations, subsequent to the occurrence of a credit rating
downgrade or “material adverse event” the immediate posting of cash collateral
or provision of an LOC may be required of the subsidiary. The following table
summarizes collateral provisions in effect as of December 31,
2004:








**Total**
    
    **Collateral
      Paid**
    
    **Remaining****Collateral
      Provisions**
    
    **Exposure**
    
    **Cash**
    
    **LOC**
    
    **Exposure****(1)*****(In
      millions)***Credit rating
      downgrade
    
    $
    349
    
    $
    162
    
    $
    18
    
    $
    169Adverse
      event
    
    
    135
    
    
    --
    
    
    22
    
    
    113Total
    
    $
    484
    
    $
    162
    
    $
    40
    
    $
    282





(1)
    As of
      February 7, 2005, our total exposure decreased to $476 million and the
      remaining exposure increased to
      $290
      million - net of $146 million of cash collateral and $40 million of LOC
      collateral provided to counterparties.








Most of our 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.





25





We have guaranteed
the obligations of the operators of the TEBSA project up to a maximum of $6.0
million (subject to escalation) under the project's operations and maintenance
agreement. In connection with the sale of TEBSA in January 2004, the purchaser
indemnified FirstEnergy against any loss under this guarantee. We have also
provided an LOC (currently at $47 million), which is renewable and declines
yearly based upon the senior outstanding debt of TEBSA.





**OFF-BALANCE
SHEET ARRANGEMENTS**





We have obligations
that are not included on our Consolidated Balance Sheets related to the sale and
leaseback arrangements involving Perry Unit 1, Beaver Valley Unit 2 and the
Bruce Mansfield Plant, which are reflected as part of the operating lease
payments disclosed above (see Notes 6 and 7). The present value of these sale
and leaseback operating lease commitments, net of trust investments, total $1.4
billion as of December 31, 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 $84 million of off-balance
sheet financing as of December 31, 2004. See Note 12 to the consolidated
financial statements for additional information regarding this
arrangement.





We have 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 we do not expect to have a material current
or future effect on our financial condition, liquidity or results of operations
are disclosed above as contractual obligations.





**MARKET RISK
INFORMATION**





We use various
market risk sensitive instruments, including derivative contracts, primarily to
manage the risk of price and interest rate fluctuations. Our Risk Policy
Committee, comprised of members of senior management, provides general
management oversight to risk management activities throughout the company. They
are responsible for promoting the effective design and implementation of sound
risk management programs. They also oversee compliance with corporate risk
management policies and established risk management practices.





*Commodity Price
Risk*





We are exposed to
market risk primarily due to fluctuations in electricity, natural gas, coal,
nuclear fuel and emission allowance prices. To manage the volatility relating to
these exposures, we use a variety of non-derivative and derivative instruments,
including forward contracts, options, futures contracts and swaps. The
derivatives are used principally for hedging purposes and, to a much lesser
extent, for trading purposes. Most of our 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 2004 is summarized in the following table:





**Increase
      (Decrease) in the Fair Value of Derivative
    Contracts**
    
    **Non-Hedge**
    
    **Hedge**
    
    **Total*****(In
      millions)***Change in the
      fair value of commodity derivative contractsOutstanding
      net asset as of January 1, 2004
    
    $
    67
    
    $
    12
    
    $
    79New contract
      value when entered
    
    
    --
    
    
    --
    
    
    --Additions/change
      in value of existing contracts
    
    
    (4
    )
    
    6
    
    
    2Change in
      techniques/assumptions
    
    
    --
    
    
    --
    
    
    --Settled
      contracts
    
    
    (1
    )
    
    (16
    )
    
    (17
    )Outstanding
      net asset as of December 31, 2004(1)
    
    
    62
    
    
    2
    
    
    64**Non-commodity
      net assets as of December 31, 2004**:Interest rate
      swaps(2)
    
    
    --
    
    
    4
    
    
    4**Net
      Assets - Derivatives Contracts as of December 31, 2004**
    
    **$**
    **62**
    
    **$**
    **6**
    
    **$**
    **68****Impact
      of Changes in Commodity Derivative Contracts****(3)**Income
      Statement Effects (Pre-Tax)
    
    $
    (5
    )
    $
    --
    
    $
    (5
    )Balance Sheet
      Effects:OCI
      (Pre-Tax)
    
    $
    --
    
    $
    (10
    )
    $
    (10
    )





(1)
    Includes $61 million in non-hedge commodity derivative contracts, which
      are offset by a regulatory liability.


(2)
    Interest rate swaps are primarily treated as fair value hedges. Changes in
      derivative values of the fair value
      hedges
      are offsetby changes
      in the hedged debts' premium or discount (see Interest Rate Swap
      Agreements
      below).


(3)
    Represents the increase in value of existing contracts, settled contracts
      and changes in
      techniques/assumptions.





26





Derivatives are
included on the Consolidated Balance Sheet as of December 31, 2004 as
follows:





**Non-Hedge**
    
    **Hedge**
    
    **Total*****(In
      millions)*****Current-**Other
      assets
    
    $
    2
    
    $
    2
    
    $
    4Other
      liabilities
    
    
    (2
    )
    
    (1
    )
    
    (3
    )**Non-Current-**Other
      deferred charges
    
    
    62
    
    
    15
    
    
    77Other
      noncurrent liabilities
    
    
    --
    
    
    (10
    )
    
    (10
    )**Net
      assets**
    
    **$******
    ******62**
    
    **$******
    ******6**
    
    **$******
    ******68**








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








**Source
      of Information****-
      Fair Value by Contract Year**
    
    **2005**
    
    **2006**
    
    **2007**
    
    **2008**
    
    **Thereafter**
    
    **Total*****(In
      millions)***Prices
      actively quoted(1)
    
    $
    2
    
    $
    1
    
    $
    --
    
    $
    --
    
    $
    --
    
    $
    3Other
      external sources(2)
    
    
    17
    
    
    10
    
    
    --
    
    
    --
    
    
    --
    
    
    27Prices based
      on models
    
    
    --
    
    
    --
    
    
    10
    
    
    9
    
    
    15
    
    
    34**Total****(3)**
    
    **$**
    **19**
    
    **$**
    **11**
    
    **$**
    **10**
    
    **$**
    **9**
    
    **$**
    **15**
    
    **$**
    **64**





(1)  Exchange
traded.


(2)  Broker quote
sheets.


(3)  Includes $61
million from an embedded option that is offset by a regulatory liability and
does not affect earnings.







We perform
sensitivity analyses to estimate our exposure to the market risk of our
commodity positions. A hypothetical 10% adverse shift in quoted market prices in
the near term on both our trading and nontrading derivative instruments would
not have had a material effect on our consolidated financial position or cash
flows as of December 31, 2004. We estimate that if energy commodity prices
experienced an adverse 10% change, net income for the next twelve months would
decrease by approximately $3 million.





*Interest Rate
Risk*





Our exposure to
fluctuations in market interest rates is reduced since a significant portion of
our debt has fixed interest rates, as noted in the table below.





**Comparison
of Carrying Value to Fair Value**





**There-**
    
    
    
    **Fair****Year
      of Maturity**
    
    **2005**
    
    **2006**
    
    **2007**
    
    **2008**
    
    **2009**
    
    **after**
    
    **Total**
    
    **Value*****(Dollars
      in millions)***AssetsInvestments
      other than Cash and CashEquivalents-Fixed
      Income
    
    $
    73
    
    $
    82
    
    $
    77
    
    $
    57
    
    $
    68
    
    $
    1,729
    
    **$**
    **2,086**
    
    **$**
    **2,243**Average
      interest rate
    
    
    6.8
    %
    
    7.8
    %
    
    7.9
    %
    
    7.7
    %
    
    7.8
    %
    
    6.0
    %
    
    6.3
    %LiabilitiesLong-term
      Debt and OtherLong-term
      Obligations:Fixed rate(1)
    
    $
    495
    
    $
    1,327
    
    $
    238
    
    $
    338
    
    $
    284
    
    $
    6,674
    
    **$**
    **9,356**
    
    **$**
    **9,915**Average
      interest rate
    
    
    7.4
    %
    
    5.7
    %
    
    6.6
    %
    
    5.3
    %
    
    6.8
    %
    
    6.5
    %
    
    6.4
    %Variable rate(1)
    
    $
    215
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    1,319
    
    **$**
    **1,534**
    
    **$**
    **1,538**Average
      interest rate
    
    
    3.6
    %
    
    
    
    
    
    
    
    
    
    
    
    
    
    2.2
    %
    
    2.4
    %Preferred
      Stock Subject toMandatory
      Redemption
    
    $
    2
    
    $
    2
    
    $
    12
    
    $
    1
    
    
    
    
    
    
    
    **$**
    **17**
    
    **$**
    **16**Average
      dividend rate
    
    
    7.5
    %
    
    7.5
    %
    
    7.6
    %
    
    7.4
    %
    
    
    
    
    
    
    
    7.6
    %Short-term
      Borrowings
    
    $
    170
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    **$**
    **170**
    
    **$**
    **170**Average
      interest rate
    
    
    2.4
    %
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2.4
    %





(1)  Balances and rates
do not reflect the fixed-to-floating interest rate swap agreements discussed
below.





27





We are subject to
the inherent interest rate risks related to refinancing maturing debt by issuing
new debt securities. As discussed in Note 6 to the consolidated financial
statements, our investments in capital trusts effectively reduce future lease
obligations, also reducing interest rate risk. While fluctuations in the fair
value of our Ohio Companies' decommissioning trust balances will eventually
affect earnings (affecting OCI initially) based on the guidance provided by SFAS
115, our non-Ohio EUOC have the opportunity to recover from customers, or refund
to customers, the difference between the investments held in trust and their
decommissioning obligations. Thus, there is not expected to be an earnings
effect from fluctuations in their decommissioning trust balances. As of
December 31, 2004, decommissioning trust balances totaled $1.583 billion,
with $975 million held by our Ohio Companies and the balance held by our
non-Ohio EUOC. As of year-end 2004, trust balances of our Ohio Companies were
comprised of 64% equity securities and 36% debt instruments.





*Interest Rate
Swap Agreements*





We have utilized
fixed-to-floating interest rate swap agreements, as part of our ongoing effort
to manage the interest rate risk of our 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. During the
fourth quarter of 2004, in a period of declining interest rates, we unwound
swaps with a total notional amount of $400 million. We received $12 million in
cash gains from unwinding the swaps and interest expense will be reduced by that
amount over the term of the related hedged debt. Due to the differences between
fixed and variable debt rates, interest expense in 2004 and 2003 was reduced by
$37 million and $27 million, respectively. We increased the total notional
amount of outstanding interest rate swaps to $1.65 billion as of
December 31, 2004, from $1.15 billion at the end of 2003 from cumulative
swap activities. As of December 31, 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 3.42%.








**Fixed
      to Floating Rate**
    
    **December
      31, 2004**
    
    **December
      31, 2003****Interest
      Rate Swaps**
    
    **Notional**
    
    **Maturity**
    
    **Fair**
    
    **Notional**
    
    **Maturity**
    
    **Fair****(Fair
      value hedges)**
    
    **Amount**
    
    **Date**
    
    **Value**
    
    **Amount**
    
    **Date**
    
    **Value*****(Dollars
      in millions)***$
    200
    
    
    2006
    
    $
    (1
    )
    $
    200
    
    
    2006
    
    $
    1100
    
    
    2008
    
    
    (1
    )
    
    50
    
    
    2008
    
    
    --100
    
    
    2010
    
    
    1
    
    
    100
    
    
    2010
    
    
    1100
    
    
    2011
    
    
    2
    
    
    100
    
    
    2011
    
    
    1400
    
    
    2013
    
    
    4
    
    
    350
    
    
    2013
    
    
    (1
    )100
    
    
    2014
    
    
    2
    
    
    --
    
    
    --
    
    
    --150
    
    
    2015
    
    
    (7
    )
    
    150
    
    
    2015
    
    
    (10
    )200
    
    
    2016
    
    
    1
    
    
    --
    
    
    --
    
    
    --150
    
    
    2018
    
    
    5
    
    
    150
    
    
    2018
    
    
    150
    
    
    2019
    
    
    2
    
    
    50
    
    
    2019
    
    
    1100
    
    
    2031
    
    
    (4
    )
    
    --
    
    
    --
    
    
    --








*Equity Price
Risk*





Included in nuclear
decommissioning trusts are marketable equity securities carried at their current
fair value of approximately $951 million and $779 million as of
December 31, 2004 and 2003, respectively. A hypothetical 10% decrease in
prices quoted by stock exchanges would result in a $95 million reduction in fair
value as of December 31, 2004 (see Note 5 - Fair Value of Financial
Instruments).





**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. We engage 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.





We maintain credit
policies with respect to our 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 our credit program, we aggressively manage
the quality of our portfolio of energy contracts, evidenced by a current
weighted average risk rating for energy contract counterparties of BBB
(S&P). As of December 31, 2004, the largest credit concentration was
with one party, currently rated investment grade that represented 7% of our
total credit risk. Within our unregulated energy subsidiaries, 99% of credit
exposures, net of collateral and reserve, were with investment-grade
counterparties as of December 31, 2004.





28





**REGULATORY
MATTERS**





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





·
    restructuring
      the electric generation business and allowing the Companies' customers to
      select a competitive electric
      generation
      supplier other than the Companies;·
    establishing
      or defining the PLR obligations to customers in the Companies' service
      areas;·
    providing the
      Companies with the opportunity to recover 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;·
    continuing
      regulation of the Companies' transmission and distribution systems;
      and·
    requiring
      corporate separation of regulated and unregulated business
      activities.





The EUOC recognize,
as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU have authorized
for recovery from customers in future periods or for which authorization is
probable. Without the probability of such authorization, costs currently
recorded as regulatory assets would have been charged to income as incurred. All
regulatory assets are expected to be recovered from customers under the
Companies' respective transition and regulatory plans. Based on those plans, the
Companies continue to bill and collect cost-based rates for their transmission
and distribution services, which remain regulated; accordingly, it is
appropriate that the Companies continue the application of SFAS 71 to those
operations. Regulatory assets that do not earn a current return totaled
approximately $240 million as of December 31, 2004.








**Regulatory
      Assets**
    
    
    **Increase****As of
      December 31**
    **2004**
    **2003**
    **(Decrease)*****(In
      millions)***OE
    $1,116
    $1,451
    $
      (335)CEI
    959
    1,056
    (97)TE
    375
    459
    (84)Penn*
    --
    28
    (28)JCP&L
    2,176
    2,558
    (382)Met-Ed
    693
    1,028
    (335)Penelec
    200
    497
    (297)ATSI
    13
    --
    13Total
    $5,532
    $7,077
    $(1,545)





*  Changes in Penn's
net regulatory asset components in 2004 resulted in net regulatory
liabilities of


approximately $18 million
included in Other Noncurrent Liabilities on the
Consolidated Balance Sheet


as of December 31, 2004.








29





Regulatory assets
by source are as follows:








**Regulatory
      Assets By Source**
    
    
    
    
    
    **Increase****As of
      December 31**
    
    **2004**
    
    **2003**
    
    **(Decrease)*****(In
      millions)***Regulatory
      transition costs
    
    $
    4,889
    
    $
    6,427
    
    $
    (1,538
    )Customer
      shopping incentives*
    
    
    612
    
    
    371
    
    
    241Customer
      receivables for future income taxes
    
    
    246
    
    
    340
    
    
    (94
    )Societal
      benefits charge
    
    
    51
    
    
    81
    
    
    (30
    )Loss on
      reacquired debt
    
    
    89
    
    
    75
    
    
    14Employee
      postretirement benefits costs
    
    
    65
    
    
    77
    
    
    (12
    )Nuclear
      decommissioning, decontaminationand spent
      fuel disposal costs
    
    
    (169
    )
    
    (96
    )
    
    (73
    )Asset removal
      costs
    
    
    (340
    )
    
    (321
    )
    
    (19
    )Property
      losses and unrecovered plant costs
    
    
    50
    
    
    70
    
    
    (20
    )Other
    
    
    39
    
    
    53
    
    
    (14
    )Total
    
    $
    5,532
    
    $
    7,077
    
    $
    (1,545
    )








*
    The
      Ohio Companies are deferring customer shopping incentives and interest
      costs as new regulatory assets in
      accordance
      withthe
      transition and rate stabilization plans. These regulatory assets, totaling
      $612 million as of
      December
      31, 2004, will be recoveredthrough
      a surcharge rate equal to the RTC rate in effect when the transition
      costs
      have been fully recovered. Recovery of the newregulatory
      assets will begin at that time and amortization
      of the
      regulatory assets for each accounting period will be equal to
      thesurcharge
      revenue recognized during
      that
      period.





*Ohio*





On February 24,
2004, the Ohio Companies filed a revised Rate Stabilization Plan to address PUCO
concerns related to the original Rate Stabilization Plan that the Ohio Companies
filed in October 2003. On June 9, 2004, the PUCO issued an order approving
the revised Rate Stabilization Plan, subject to conducting a competitive bid
process. On August 5, 2004, the Ohio Companies accepted the Rate
Stabilization Plan as modified and approved by the PUCO on August 4, 2004.
In the second quarter of 2004, the Ohio Companies implemented the accounting
modifications related to the extended amortization periods and interest cost
deferrals on the deferred customer shopping incentive balances. On
October 1 and October 4, 2004, the OCC and NOAC, respectively, filed
appeals with the Supreme Court of Ohio to overturn the June 9, 2004 PUCO
order and associated entries on rehearing.





The revised Rate
Stabilization Plan extends current generation prices through 2008, ensuring
adequate generation supply at stabilized prices, and continues the Ohio
Companies' support of energy efficiency and economic development efforts. Other
key components of the revised Rate Stabilization Plan include the
following:





·
    extension of
      the amortization period for transition costs being recovered through the
      RTC for OE from 2006 to as
      late as 2007;
      for CEI from 2008 to as late as mid-2009 and for TE from mid-2007 to as
      late as mid-2008;·
    deferral of
      interest costs on the accumulated customer shopping incentives as new
      regulatory assets; and·
    ability to
      request increases in generation charges during 2006 through 2008, under
      certain limited conditions,
      for increases
      in fuel costs and taxes.





On December 9,
2004, the PUCO rejected the auction price results from a required competitive
bid process and issued an entry stating that the pricing under the approved
revised Rate Stabilization Plan will take effect on January 1, 2006. The
PUCO may cause the Ohio Companies to undertake, no more often than annually, a
similar competitive bid process to secure generation for the years 2007 and
2008. Any acceptance of future competitive bid results would terminate the Rate
Stabilization Plan pricing, but not the related approved accounting, and not
until twelve months after the PUCO authorizes such termination.





On
December 30, 2004, the Ohio Companies filed an application with the PUCO
seeking tariff adjustments to recover increases of approximately $30 million in
transmission- and ancillary service-related costs beginning January 1,
2006. The Ohio Companies also filed an application for authority to defer costs
such as those associated with MISO Day 1, MISO Day 2, congestion fees, FERC
assessment fees, and the ATSI rate increase (described below), as applicable,
from October 1, 2003 through December 31, 2005.





30





See Note 9 to the
consolidated financial statements for further details and a complete discussion
of regulatory matters in Ohio.





*New Jersey*





In July 2003, the
NJBPU announced its JCP&L base electric rate proceeding decision, which
reduced JCP&L's annual revenues effective August 1, 2003 and disallowed
$153 million of deferred energy costs. The NJBPU decision also provided for an
interim return on equity of 9.5% on JCP&L's rate base. The decision
ordered  a Phase II proceeding be conducted to review whether JCP&L is
in compliance with current service reliability and quality standards. The BPU
also ordered that any expenditures and projects undertaken by JCP&L to
increase its system's reliability be reviewed as part of the Phase II
proceeding, to determine their prudence and reasonableness for rate recovery. 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. 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. 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. JCP&L filed an August 15,
2003 interim motion for rehearing and reconsideration with the NJBPU and a
June 1, 2004 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.
Management is unable to predict when a decision may be reached by the
NJBPU.


On July 16,
2004, JCP&L filed the Phase II petition and testimony with the NJBPU
requesting an increase in base rates of $36 million for 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. The Ratepayer Advocate filed testimony on November 16, 2004, JCP&L
submitted rebuttal testimony on January 4, 2005. Settlement conferences are
ongoing.




See Note 9 to the
consolidated financial statements for further details and a complete discussion
of regulatory matters in New Jersey.





*Pennsylvania*





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. Met-Ed and Penelec
are authorized to continue deferring differences between NUG contract costs and
current market prices.





On January 12,
2005, Met-Ed and Penelec filed, before the PPUC, a request for deferral of
transmission-related costs beginning January 1, 2005 estimated to be
approximately $8 million per month.





See Note 9 to the
consolidated financial statements for further details and a complete discussion
of regulatory matters in Pennsylvania.





*Transmission*





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 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.





On November 1,
2004, ATSI requested authority from the FERC to defer approximately $54 million
of vegetation management costs ($13 million deferred as of December 31,
2004 pending authorization) estimated to be incurred from 2004 through
2007. The FERC approved ATSI's request to defer those costs on March 4,
2005.





31





ATSI and MISO filed
with the FERC on December 2, 2004, seeking approval for ATSI to have
transmission rates established based on a FERC-approved cost of service formula
rate included in Attachment O under the MISO tariff. The ATSI Network Service
net revenue requirement increased under the formula rate to approximately $159
million. On January 28, 2005, the FERC accepted for filing the revised
tariff sheets to become effective February 1, 2005, subject to refund, and
ordered a public hearing be held to address the reasonableness of the proposal
to eliminate the voltage-differentiated rate design for the ATSI
zone.





*Reliability
Initiatives*





In 2004, we
completed implementation of all actions and initiatives related to enhancing
area reliability, improving voltage and reactive management, operator readiness
and training, and emergency response preparedness recommended by various
governmental, industry and ad hoc reliability entities (PUCO, FERC, NERC and the
U.S. - Canada Power System Outage Task Force) for completion in 2004. We
certified to NERC on June 30, 2004, that we had completed our initiatives
with minor exceptions noted, and an independent team led by NERC verified the
implementation. Further, we reported to NERC on December 28, 2004 that the
minor exceptions were essentially complete.





We are proceeding
with the implementation of the recommendations that were to be completed
subsequent to 2004 and will continue to periodically assess the
FERC-ordered Reliability Study recommendations for forecasted 2009 system
conditions recognizing revised load forecasts and other changing system
conditions which may impact the recommendations. Thus far, implementation of the
recommendations has not required, nor is expected to require, substantial
investment in new, or material upgrades to existing equipment. We note, 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. Finally, the PUCO is continuing to review our filing that
addressed upgrades to control room computer hardware and software and
enhancements to the training of control room operators, before determining the
next steps, if any, in the proceeding. See Note 9 to the consolidated financial
statements for a more detailed discussion of reliability initiatives, including
actions by the PPUC that impact Met-Ed, Penelec and Penn.





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. As a result of an
investigation into these outages, the NJBPU issued an order to JCP&L on
July 23, 2004 to implement actions to improve reliability in accordance
with a Special Reliability Master (SRM) report findings and an operations
audit.





See Note 9 to the
consolidated financial statements for a more detailed discussion of reliability
initiatives, including actions by the PPUC, that impact Met-Ed, Penelec and
Penn.





**ENVIRONMENTAL
MATTERS**





We believe we are
in compliance with current SO 2 and NO x reduction
requirements under the Clean Air Act Amendments of 1990. In 1998, the EPA
finalized regulations requiring additional NO x reductions from
the Companies' Ohio and Pennsylvania facilities. Various regulatory and judicial
actions have since sought to further define NO x reduction
requirements (see Note 13(C) - Environmental Matters). We continue to evaluate
our compliance plans and other compliance options.





*Clean Air Act
Compliance*





The Companies are
required to meet federally approved SO 2 regulations.
Violations of such regulations can result in shutdown of the generating unit
involved and/or civil or criminal penalties of up to $32,500 for each day the
unit is in violation. The EPA has an interim enforcement policy for
SO 2 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 SO 2 reduction
requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur
fuel, generating more electricity from lower-emitting plants, and/or using
emission allowances. NO x reductions
required by the 1990 Amendments are being achieved through combustion controls
and the generation of more electricity at lower-emitting plants. In September
1998, the EPA finalized regulations requiring additional NO x reductions from
the Companies' facilities. The EPA's NO x Transport Rule
imposes uniform reductions of NO x emissions (an
approximate 85% reduction in utility plant NO x emissions from
projected 2007 emissions) across a region of nineteen states (including
Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based
on a conclusion that such NO x emissions are
contributing significantly to ozone levels in the eastern United States. The
Companies believe their facilities are also complying with NO x budgets
established under State Implementation Plans (SIP) through combustion controls
and post-combustion controls, including Selective Catalytic Reduction and
Selective Non-Catalytic Reduction systems, and/or using emission
allowances.





32





*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 Michigan, New Jersey,
Ohio and Pennsylvania) and the District of Columbia based on proposed findings
that air pollution emissions from 29 eastern states and the District of Columbia
significantly contribute to nonattainment of the NAAQS for fine particles and/or
the "8-hour" ozone NAAQS in other states. The EPA has proposed the Interstate
Air Quality Rule to "cap-and-trade" NO x and SO 2 emissions in two
phases (Phase I in 2010 and Phase II in 2015). According to the EPA,
SO 2 emissions would be
reduced by approximately 3.6 million tons annually by 2010, across states
covered by the rule, with reductions ultimately reaching more than 5.5 million
tons annually. NO x emission
reductions would measure about 1.5 million tons in 2010 and 1.8 million tons in
2015. The future cost of compliance with these proposed regulations 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 SO 2 and NO x emission caps under
the EPA's proposed Interstate Air Quality Rule. Phase II of the mercury
"cap-and-trade" program would be implemented in 2018 to cap nationwide mercury
emissions from coal-fired power plants at 15 tons per year. The EPA has agreed
to choose between these two options and issue a final rule by March 15,
2005. The future cost of compliance with these regulations may be
substantial.





*W. H. Sammis
Plant*





In 1999 and 2000,
the EPA issued NOV or Compliance Orders to nine utilities covering 44 power
plants, including the W. H. Sammis Plant, which is owned by OE and Penn. In
addition, the U.S. Department of Justice filed eight civil complaints against
various investor-owned utilities, which included a complaint against OE and Penn
in the U.S. District Court for the Southern District of Ohio. These cases are
referred to as New Source Review cases. The NOV and complaint allege violations
of the Clean Air Act based on operation and maintenance of the W. H. Sammis
Plant dating back to 1984. The complaint requests permanent injunctive relief to
require the installation of "best available control technology" and civil
penalties of up to $27,500 per day of violation. On August 7, 2003, the
United States District Court for the Southern District of Ohio ruled that 11
projects undertaken at the W. H. Sammis Plant between 1984 and 1998 required
pre-construction permits under the Clean Air Act. The ruling concludes the
liability phase of the case, which deals with applicability of Prevention of
Significant Deterioration provisions of the Clean Air Act. The remedy phase of
the trial to address any civil penalties and what, if any, actions should be
taken to further reduce emissions at the plant has been delayed without
rescheduling 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
December 31, 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.





33




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 Sheets as of
December 31, 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 as of
December 31, 2004. The Companies accrue environmental liabilities only when
they can conclude that it is probable that they have an obligation for such
costs and can reasonably determine the amount of such costs. Unasserted claims
are reflected in the Companies’ determination of environmental liabilities and
are accrued in the period that they are both probable and reasonably
estimable.


*Climate Change*


In December 1997,
delegates to the United Nations' climate summit in Japan adopted an agreement,
the Kyoto Protocol (Protocol), to address global warming by reducing the amount
of man-made greenhouse gases emitted by developed countries by 5.2% from 1990
levels between 2008 and 2012. The United States signed the Protocol in 1998 but
it failed to receive the two-thirds vote of the United States 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 CO2emissions could
require significant capital and other expenditures. However, the CO2emissions 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-CO2emitting 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 require material capital
expenditures.





**OTHER LEGAL
PROCEEDINGS**





*Power Outages
and Related Litigation*





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. The other two cases were
appealed. One case was dismissed and no further appeal was sought. The remaining
case is pending. 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 timetable for a
decision on the motion to dismiss has been established by the Court. 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 initiated against the Companies. In particular, if FirstEnergy or its
subsidiaries were ultimately determined to have legal liability in connection
with these proceedings, it could have a material adverse effect on FirstEnergy's
or its subsidiaries' financial condition and results of operations.





34





*Nuclear Plant
Matters*


In late 2003, FENOC
received a subpoena from a grand jury 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 Nuclear Power Station. First Energy is
unable to predict the outcome of this investigation. On
December 10, 2004, FirstEnergy received a letter from the United States
Attorney's Office stating that FENOC is a target of the federal grand jury
investigation into alleged false statements relating to the Davis-Besse Nuclear
Power Station outage made to the NRC in the Fall of 2001 in response to NRC
Bulletin 2001-01. The letter also said that the designation of FENOC as a target
indicates that, in the view of the prosecutors assigned to the matter, it is
likely that federal charges will be returned against FENOC by the grand jury. On
February 10, 2005, FENOC received an additional subpoena for documents related
to root cause reports regarding reactor head degradation and the assessment of
reactor head management issues at Davis-Besse. 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.


On August 12,
2004, the NRC notified FENOC 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. FENOC operates the Perry Nuclear Power Plant,
which is either owned or leased by OE, CEI, TE and Penn. Although the NRC noted
that the plant continues to operate safely, the agency has indicated that its
increased oversight will include an extensive NRC team inspection to assess the
equipment problems and the sufficiency of FENOC's corrective actions. The
outcome of these matters could include NRC
enforcement action or other impacts on operating authority. As a result, these
matters could have a material adverse effect on FirstEnergy's or its
subsidiaries' financial condition.





*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 July 27,
2004, FirstEnergy announced that it had reached an agreement to resolve pending
lawsuits alleging violations of federal securities laws and related state laws
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 and the extended outage
at the Davis-Besse Nuclear Power Station. 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 paid
$71.92 million, based on a contractual pre-allocation, and FirstEnergy paid
$17.98 million, which resulted in an after-tax charge against FirstEnergy's
second quarter earnings of $11 million or $0.03 per share of common stock (basic
and diluted). On December 30, 2004, the court approved the
settlement.





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, have
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. On
December 30, 2004, FirstEnergy received a second subpoena asking for
documents relating to issues raised during the SEC's PUHCA examination.
FirstEnergy has cooperated fully with the informal inquiry and will continue to
do so with the formal investigation. If it were ultimately determined that
FirstEnergy or its subsidiaries have legal liability or are otherwise made
subject to liability based on the above matter, it could have a material adverse
effect on FirstEnergy's or its subsidiaries' financial condition and results of
operations.





**CRITICAL
ACCOUNTING POLICIES**





We prepare our
consolidated financial statements in accordance with GAAP. Application of these
principles often requires a high degree of judgment, estimates and assumptions
that affect financial results. All of our assets are subject to their own
specific risks and uncertainties and are regularly reviewed for impairment. Our
more significant accounting policies are described below.





*Regulatory
Accounting*





Our regulated
services segment is subject to regulation that sets the prices (rates) we are
permitted to charge our customers based on costs that the regulatory agencies
determine we are permitted to recover. At times, regulators permit the future
recovery through rates of costs that would be currently charged to expense by an
unregulated company. This ratemaking process results in the recording of
regulatory assets based on anticipated future cash inflows. We regularly review
these assets to assess their ultimate recoverability within the approved
regulatory guidelines. Impairment risk associated with these assets relates to
potentially adverse legislative, judicial or regulatory actions in the future.





35





*Revenue
Recognition*





We follow the
accrual method of accounting for revenues, recognizing revenue for electricity
that has been delivered to customers but not yet billed through the end of the
accounting period. The determination of electricity sales to individual
customers is based on meter readings, which occur on a systematic basis
throughout the month. At the end of each month, electricity delivered to
customers since the last meter reading is estimated and a corresponding accrual
for unbilled sales is recognized. The determination of unbilled sales requires
management to make estimates regarding electricity available for retail load,
transmission and distribution line losses, demand by customer class,
weather-related impacts, prices in effect for each customer class and
electricity provided by alternative suppliers.





*Pension and
Other Postretirement Benefits Accounting*


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





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





In selecting an
assumed discount rate, we consider currently available rates of return on
high-quality fixed income investments expected to be available during the period
to maturity of the pension and other postretirement benefit obligations. Due to
recent declines in corporate bond yields and interest rates in general, we
reduced the assumed discount rate as of December 31, 2004 to 6.00% from
6.25% and 6.75% used as of December 31, 2003 and 2002, respectively.





Our assumed rate of
return on pension plan assets considers historical market returns and economic
forecasts for the types of investments held by our pension trusts. In 2004, 2003
and 2002, plan assets actually earned 11.1%, 24.2% and (11.3)%, respectively.
Our pension costs in 2004 were computed assuming a 9.0% rate of return on plan
assets based upon projections of future returns and our pension trust investment
allocation of approximately 68% equities, 29% bonds, 2% real estate and 1% cash.





In the third
quarter of 2004, we made a $500 million voluntary contribution to our 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. Our
election to pre-fund the plan is expected to eliminate that funding requirement.





As a result of our
voluntary contribution and the increased market value of pension plan assets, we
reduced our accrued benefit cost as of December 31, 2004 by $424 million.
As prescribed by SFAS 87, we reduced our additional minimum liability by $15
million, recording a decrease in an intangible asset of $9 million and crediting
OCI by $6 million. The balance in AOCL of $296 million (net of $208 million in
deferred taxes) will reverse in future periods to the extent the fair value of
trust assets exceeds the accumulated benefit obligation.





Health care cost
trends have significantly increased and will affect future OPEB costs. The 2004
and 2005 composite health care trend rate assumptions are approximately 10%-12%
and 9%-11%, respectively, gradually decreasing to 5% in later years. In
determining our trend rate assumptions, we included the specific provisions of
our health care plans, the demographics and utilization rates of plan
participants, actual cost increases experienced in our health care plans, and
projections of future medical trend rates. The effect on our pension and OPEB
costs and liabilities from changes in key assumptions are as follows:





**Increase
      in Costs from Adverse Changes in Key Assumptions****Assumption**
    
    **Adverse
      Change**
    
    **Pension**
    
    **OPEB**
    
    **Total*****(In
      millions)***Discount
      rate
    
    
    Decrease by
      0.25
    %
    $
    10
    
    $
    5
    
    $
    15Long-term
      return on assets
    
    
    Decrease by
      0.25
    %
    $
    10
    
    $
    1
    
    $
    11Health care
      trend rate
    
    
    Increase by
      1
    %
    
    na
    
    $
    19
    
    $
    19**Increase
      in Minimum Liability**Discount
      rate
    
    
    Decrease by
      0.25
    %
    $
    110
    
    
    na
    
    $
    110








36





*Ohio Transition
Cost Amortization*





In connection with
the Ohio Companies' transition plan, the PUCO determined allowable transition
costs based on amounts recorded on the regulatory books of the Ohio Companies.
These costs exceeded those deferred or capitalized on FirstEnergy's balance
sheet prepared under GAAP since they included certain costs which had 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 transition 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, we periodically evaluate our 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, we recognize a loss -
calculated as the difference between the carrying value and the estimated fair
value of the asset (discounted future net cash flows).





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





*Nuclear
Decommissioning*





In accordance with
SFAS 143, we recognize an ARO for the future decommissioning of our nuclear
power plants. The ARO liability represents an estimate of the fair value of our
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. We used an expected cash flow
approach 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, we evaluate goodwill for impairment at least
annually and make such evaluations more frequently if indicators of impairment
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 we recognize a
loss - calculated as the difference between the implied fair value of a
reporting unit's goodwill and the carrying value of the goodwill. Our annual
review was completed in the third quarter of 2004 with no impairment
indicated.





SFAS 142 requires
the goodwill of a reporting unit to be tested for impairment if there is a
more-likely-than-not expectation that the reporting unit or a significant asset
group within the reporting unit will be sold. In December 2004, the FSG
subsidiaries qualified as held for sale in accordance with SFAS 144. As required
by SFAS 142, the goodwill of FSG was tested for impairment, resulting in a
non-cash charge of $36 million in the fourth quarter of 2004.





The forecasts used
in our evaluations of goodwill reflect operations consistent with our general
business assumptions. Unanticipated changes in those assumptions could have a
significant effect on our future evaluations of goodwill.





37





**NEW
ACCOUNTING STANDARDS AND INTERPRETATIONS**





*SFAS 123
(revised 2004) “Share-Based Payment”*


In December 2004,
the FASB issued this revision to SFAS 123, which requires expensing stock
options in the financial statements. Important to applying the new standard is
understanding how to (1) measure the fair value of stock-based compensation
awards and (2) recognize the related compensation cost for those awards. For an
award to qualify for equity classification, it must meet certain criteria in
SFAS 123(R). An award that does not meet those criteria will be classified as a
liability and remeasured each period. SFAS 123(R) retains SFAS 123's
requirements on accounting for income tax effects of stock-based compensation.
The effective date for FirstEnergy is July 1, 2005 and the Company will be
applying modified prospective application, without restatement of prior interim
periods. Any potential cumulative adjustments have not been determined.
FirstEnergy uses the Black-Scholes option pricing model to value options and
will continue to do so upon adoption of SFAS 123(R). The impacts of the fair
value recognition provisions of SFAS 123 on FirstEnergy’s net income and
earnings per share for 2002 through 2004 are disclosed in Note 4 to the
consolidated financial statements. FirstEnergy is considering alternative
compensation strategies in conjunction with the adoption of SFAS
123(R).


*EITF Issue No.
03-1, "The Meaning of Other-Than-Temporary Impairment and its Application to
Certain Investments"*





In March 2004,
the EITF reached a consensus on the application guidance for EITF 03-1, which
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.










38





**FIRSTENERGY
CORP.**





**CONSOLIDATED
STATEMENTS OF INCOME**








**For
      the Years Ended December 31,**
    **2004**
    
    **2003**
    
    **2002****(In
      thousands, except per share amounts)****REVENUES:**Electric
      utilities
    $
    9,064,853
    
    $
    8,962,201
    
    $
    9,165,805Unregulated
      businesses
    
    3,388,193
    
    
    2,712,687
    
    
    2,287,549Total
      revenues
    
    12,453,046
    
    
    11,674,888
    
    
    11,453,354**EXPENSES:**Fuel and
      purchased power
    
    4,469,484
    
    
    4,159,143
    
    
    3,309,658Other
      operating expenses
    
    3,558,676
    
    
    3,796,062
    
    
    3,927,370Provision for
      depreciation
    
    589,652
    
    
    606,436
    
    
    721,493Amortization
      of regulatory assets
    
    1,166,323
    
    
    1,079,337
    
    
    940,991Deferral of
      new regulatory assets
    
    (256,795
    )
    
    (194,261
    )
    
    (183,947
    )Goodwill
      impairment (Note 2(H))
    
    36,471
    
    
    116,988
    
    
    --General
      taxes
    
    677,757
    
    
    637,967
    
    
    649,400Total
      expenses
    
    10,241,568
    
    
    10,201,672
    
    
    9,364,965**CLAIM
      SETTLEMENT (Note 8)**
    
    --
    
    
    167,937
    
    
    --**INCOME
      BEFORE INTEREST AND INCOME TAXES**
    
    2,211,478
    
    
    1,641,153
    
    
    2,088,389**NET
      INTEREST CHARGES:**Interest
      expense
    
    670,945
    
    
    798,911
    
    
    904,697Capitalized
      interest
    
    (25,581
    )
    
    (31,900
    )
    
    (24,474
    )Subsidiaries’
      preferred stock dividends
    
    21,413
    
    
    42,369
    
    
    75,647Net interest
      charges
    
    666,777
    
    
    809,380
    
    
    955,870**INCOME
      TAXES**
    
    670,922
    
    
    407,524
    
    
    514,134**INCOME
      BEFORE DISCONTINUED OPERATIONS AND CUMULATIVE****EFFECT
      OF ACCOUNTING CHANGE**
    
    873,779
    
    
    424,249
    
    
    618,385Discontinued
      operations (net of income taxes (benefit) of $3,038,000,($3,064,000)
      and $14,560,000, respectively) (Note 2(J))
    
    4,396
    
    
    (103,632
    )
    
    (65,581
    )Cumulative
      effect of accounting change (net of income taxes of$72,516,000)
      (Note 2(K))
    
    --
    
    
    102,147
    
    
    --**NET
      INCOME**
    $
    878,175
    
    $
    422,764
    
    $
    552,804**BASIC
      EARNINGS PER SHARE OF COMMON STOCK:**Income before
      discontinued operations and cumulative effect ofaccounting
      change
    $
    2.67
    
    $
    1.40
    
    $
    2.11Discontinued
      operations (Note 2(J))
    
    0.01
    
    
    (0.34
    )
    
    (0.22
    )Cumulative
      effect of accounting change (Note 2(K))
    
    --
    
    
    0.33
    
    
    --Net
      income
    $
    2.68
    
    $
    1.39
    
    $
    1.89**WEIGHTED
      AVERAGE NUMBER OF BASIC SHARES OUTSTANDING**
    
    327,387
    
    
    303,582
    
    
    293,194**DILUTED
      EARNINGS PER SHARE OF COMMON STOCK:**Income before
      discontinued operations and cumulative effect ofaccounting
      change
    $
    2.66
    
    $
    1.40
    
    $
    2.10Discontinued
      operations (Note 2(J))
    
    0.01
    
    
    (0.34
    )
    
    (0.22
    )Cumulative
      effect of accounting change (Note 2(K))
    
    --
    
    
    0.33
    
    
    --Net
      income
    $
    2.67
    
    $
    1.39
    
    $
    1.88**WEIGHTED
      AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING**
    
    328,982
    
    
    304,972
    
    
    294,421








The accompanying
Notes to Consolidated Financial Statements are an integral part of these
statements.











39





**FIRSTENERGY
CORP.**





**CONSOLIDATED
BALANCE SHEETS**





**As of
      December 31,**
    **2004**
    
    **2003*****(In
      thousands)*****ASSETS****CURRENT
      ASSETS:**Cash and cash
      equivalents
    $
    52,941
    
    $
    113,975Receivables-Customers
      (less accumulated provisions of $34,476,000 and
    $50,247,000,respectively,
      for uncollectible accounts)
    
    979,242
    
    
    1,000,259Other (less
      accumulated provisions of $26,070,000 and $18,283,000,respectively,
      for uncollectible accounts)
    
    377,195
    
    
    505,241Materials and
      supplies, at average cost-Owned
    
    363,547
    
    
    325,303Under
      consignment
    
    94,226
    
    
    95,719Prepayments
      and other
    
    145,196
    
    
    202,8142,012,347
    
    
    2,243,311**PROPERTY,
      PLANT AND EQUIPMENT:**In
      service
    
    22,213,218
    
    
    21,594,746Less--Accumulated
      provision for depreciation
    
    9,413,730
    
    
    9,105,30312,799,488
    
    
    12,489,443Construction
      work in progress
    
    678,868
    
    
    779,47913,478,356
    
    
    13,268,922**INVESTMENTS:**Nuclear plant
      decommissioning trusts
    
    1,582,588
    
    
    1,351,650Investments
      in lease obligation bonds (Note 6)
    
    951,352
    
    
    989,425Certificates
      of deposit (Note 10(C))
    
    --
    
    
    277,763Other
    
    740,026
    
    
    878,8533,273,966
    
    
    3,497,691**DEFERRED
      CHARGES:**Regulatory
      assets
    
    5,532,087
    
    
    7,076,923Goodwill
    
    6,050,277
    
    
    6,127,883Other
    
    720,911
    
    
    695,21812,303,275
    
    
    13,900,024$
    31,067,944
    
    $
    32,909,948**LIABILITIES
      AND CAPITALIZATION****CURRENT
      LIABILITIES:**Currently
      payable long-term debt
    $
    940,944
    
    $
    1,754,197Short-term
      borrowings (Note 12)
    
    170,489
    
    
    521,540Accounts
      payable
    
    610,589
    
    
    725,239Accrued
      taxes
    
    657,219
    
    
    669,529Other
    
    929,194
    
    
    801,6623,308,435
    
    
    4,472,167**CAPITALIZATION**(See
      Consolidated Statement of Capitalization):Common
      stockholders’ equity
    
    8,589,294
    
    
    8,289,341Preferred
      stock of consolidated subsidiaries not subject to mandatory
      redemption
    
    335,123
    
    
    335,123Long-term
      debt and other long-term obligations
    
    10,013,349
    
    
    9,789,06618,937,766
    
    
    18,413,530**NONCURRENT
      LIABILITIES:**Accumulated
      deferred income taxes
    
    2,324,097
    
    
    2,178,075Asset
      retirement obligations (Note 11)
    
    1,077,557
    
    
    1,179,493Power
      purchase contract loss liability
    
    2,001,006
    
    
    2,727,892Retirement
      benefits
    
    1,238,973
    
    
    1,591,006Lease market
      valuation liability
    
    936,200
    
    
    1,021,000Other
    
    1,243,910
    
    
    1,326,7858,821,743
    
    
    10,024,251**COMMITMENTS,
      GUARANTEES AND CONTINGENCIES**(Notes 6 and
      13)$
    31,067,944
    
    $
    32,909,948





The accompanying
Notes to Consolidated Financial Statements are an integral part of these balance
sheets.





40





**FIRSTENERGY
CORP.**





**CONSOLIDATED
STATEMENTS OF CAPITALIZATION**








**As
      of December 31,**
    **2004**
    
    **2003***(Dollars
      in thousands, except per share amounts)*COMMON
      STOCKHOLDERS’ EQUITY:Common
      stock, $0.10 par value -authorized 375,000,000 shares-329,836,276
      shares outstanding
    $
    32,984
    
    $
    32,984Other
      paid-in capital
    
    7,055,676
    
    
    7,062,825Accumulated
      other comprehensive loss (Note 2(I))
    
    (313,112
    )
    
    (352,649
    )Retained
      earnings (Note 10(A))
    
    1,856,863
    
    
    1,604,385Unallocated
      employee stock ownership plan common stock-2,032,800
      and 2,896,951 shares, respectively (Note 4(B))
    
    (43,117
    )
    
    (58,204
    )Total
      common stockholders’ equity
    
    8,589,294
    
    
    8,289,341








**Number
      of Shares**
      **Outstanding**
    
    **Optional**
      **Redemption
      Price****2004**
    
    **2003**
    
    **Per
      Share**
    
    **Aggregate**PREFERRED
      STOCK OF CONSOLIDATEDSUBSIDIARIES
      NOT SUBJECT TOMANDATORY
      REDEMPTION (Note 10(B)):Ohio
      Edison CompanyCumulative,
      $100 par value-Authorized
      6,000,000 shares3.90%
    
    152,510
    
    
    152,510
    
    $
    103.63
    
    $
    15,804
    
    
    15,251
    
    
    15,2514.40%
    
    176,280
    
    
    176,280
    
    
    108.00
    
    
    19,038
    
    
    17,628
    
    
    17,6284.44%
    
    136,560
    
    
    136,560
    
    
    103.50
    
    
    14,134
    
    
    13,656
    
    
    13,6564.56%
    
    144,300
    
    
    144,300
    
    
    103.38
    
    
    14,917
    
    
    14,430
    
    
    14,430Total
    
    609,650
    
    
    609,650
    
    
    
    
    
    63,893
    
    
    60,965
    
    
    60,965Pennsylvania
      Power CompanyCumulative,
      $100 par value-Authorized
      1,200,000 shares4.24%
    
    40,000
    
    
    40,000
    
    
    103.13
    
    
    4,125
    
    
    4,000
    
    
    4,0004.25%
    
    41,049
    
    
    41,049
    
    
    105.00
    
    
    4,310
    
    
    4,105
    
    
    4,1054.64%
    
    60,000
    
    
    60,000
    
    
    102.98
    
    
    6,179
    
    
    6,000
    
    
    6,0007.75%
    
    250,000
    
    
    250,000
    
    
    100.00
    
    
    25,000
    
    
    25,000
    
    
    25,000Total
    
    391,049
    
    
    391,049
    
    
    
    
    
    39,614
    
    
    39,105
    
    
    39,105Cleveland
      Electric Illuminating CompanyCumulative,
      without par value-Authorized
      4,000,000 shares$
      7.40 Series A
    
    500,000
    
    
    500,000
    
    
    101.00
    
    
    50,500
    
    
    50,000
    
    
    50,000Adjustable
      Series L
    
    474,000
    
    
    474,000
    
    
    100.00
    
    
    47,400
    
    
    46,404
    
    
    46,404Total
    
    974,000
    
    
    974,000
    
    
    
    
    
    97,900
    
    
    96,404
    
    
    96,404Toledo
      Edison CompanyCumulative,
      $100 par value-Authorized
      3,000,000 shares$
      4.25
    
    160,000
    
    
    160,000
    
    
    104.63
    
    
    16,740
    
    
    16,000
    
    
    16,000$
      4.56
    
    50,000
    
    
    50,000
    
    
    101.00
    
    
    5,050
    
    
    5,000
    
    
    5,000$
      4.25
    
    100,000
    
    
    100,000
    
    
    102.00
    
    
    10,200
    
    
    10,000
    
    
    10,000310,000
    
    
    310,000
    
    
    
    
    
    31,990
    
    
    31,000
    
    
    31,000Cumulative,
      $25 par value-Authorized
      12,000,000 shares$2.365
    
    1,400,000
    
    
    1,400,000
    
    
    27.75
    
    
    38,850
    
    
    35,000
    
    
    35,000Adjustable
      Series A
    
    1,200,000
    
    
    1,200,000
    
    
    25.00
    
    
    30,000
    
    
    30,000
    
    
    30,000Adjustable
      Series B
    
    1,200,000
    
    
    1,200,000
    
    
    25.00
    
    
    30,000
    
    
    30,000
    
    
    30,0003,800,000
    
    
    3,800,000
    
    
    
    
    
    98,850
    
    
    95,000
    
    
    95,000Total
    
    4,110,000
    
    
    4,110,000
    
    
    
    
    
    130,840
    
    
    126,000
    
    
    126,000Jersey
      Central Power & Light CompanyCumulative,
      $100 stated value-Authorized
      15,600,000 shares4.00%
      Series
    
    125,000
    
    
    125,000
    
    
    106.50
    
    
    13,313
    
    
    12,649
    
    
    12,649





41





**FIRSTENERGY
CORP.**





**CONSOLIDATED
STATEMENTS OF CAPITALIZATION** (Cont’d)





**LONG-TERM
DEBT AND OTHER LONG-TERM OBLIGATIONS
(Cont'd)** ***(In
thousands)***


**(Interest
rates reflect weighted average rates)**


**FIRST
      MORTGAGE BONDS**
    
    **SECURED
      NOTES**
    
    **UNSECURED
      NOTES**
    
    **TOTAL****As
      of December 31,**
    
    
    **2004**
    
    **2003**
    
    
    
    **2004**
    
    **2003**
    
    
    
    **2004**
    
    **2003**
    
    **2004**
    
    **2003**Ohio
      Edison Co.-Due
      2004-2009
    
    6.88
    %
    $
    80,000
    
    $
    80,000
    
    
    7.61
    %
    $
    67,476
    
    $
    229,257
    
    
    4.46
    %
    $
    175,000
    
    $
    526,725Due
      2010-2014
    
    --
    
    
    --
    
    
    --
    
    
    7.16
    %
    
    1,257
    
    
    1,256
    
    
    3.70
    %
    
    50,000
    
    
    --Due
      2015-2019
    
    --
    
    
    --
    
    
    --
    
    
    3.80
    %
    
    156,725
    
    
    59,000
    
    
    5.04
    %
    
    206,000
    
    
    150,000Due
      2020-2024
    
    --
    
    
    --
    
    
    --
    
    
    7.01
    %
    
    60,443
    
    
    60,443
    
    
    3.87
    %
    
    50,000
    
    
    --Due
      2025-2029
    
    --
    
    
    --
    
    
    --
    
    
    5.75
    %
    
    119,734
    
    
    13,522
    
    
    --
    
    
    --
    
    
    --Due
      2030-2034
    
    --
    
    
    --
    
    
    --
    
    
    2.19
    %
    
    359,800
    
    
    308,012
    
    
    3.35
    %
    
    30,000
    
    
    --Total-Ohio
      Edison
    
    
    
    
    80,000
    
    
    80,000
    
    
    
    
    
    765,435
    
    
    671,490
    
    
    
    
    
    511,000
    
    
    676,725
    
    $
    1,356,435
    
    $
    1,428,215Cleveland
      ElectricIlluminating
      Co.-Due
      2004-2009
    
    6.86
    %
    
    125,000
    
    
    125,000
    
    
    7.29
    %
    
    271,700
    
    
    622,485
    
    
    --
    
    
    --
    
    
    27,700Due
      2010-2014
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    5.72
    %
    
    378,700
    
    
    378,700Due
      2015-2019
    
    --
    
    
    --
    
    
    --
    
    
    6.23
    %
    
    412,630
    
    
    412,630
    
    
    --
    
    
    --
    
    
    --Due
      2020-2024
    
    --
    
    
    --
    
    
    --
    
    
    5.35
    %
    
    180,560
    
    
    186,660
    
    
    --
    
    
    --
    
    
    --Due
      2025-2029
    
    --
    
    
    --
    
    
    --
    
    
    7.59
    %
    
    148,843
    
    
    148,843
    
    
    --
    
    
    --
    
    
    --Due
      2030-2034
    
    --
    
    
    --
    
    
    --
    
    
    2.79
    %
    
    180,995
    
    
    30,000
    
    
    7.87
    %
    
    130,793
    
    
    103,093Total-Cleveland
      Electric
    
    
    
    
    125,000
    
    
    125,000
    
    
    
    
    
    1,194,728
    
    
    1,400,618
    
    
    
    
    
    509,493
    
    
    509,493
    
    
    1,829,221
    
    
    2,035,111Toledo
      Edison Co.-Due
      2004-2009
    
    --
    
    
    --
    
    
    145,000
    
    
    7.13
    %
    
    30,000
    
    
    100,000
    
    
    --
    
    
    --
    
    
    85,250Due
      2020-2024
    
    --
    
    
    --
    
    
    --
    
    
    5.37
    %
    
    166,300
    
    
    144,500
    
    
    --
    
    
    --
    
    
    --Due
      2025-2029
    
    --
    
    
    --
    
    
    --
    
    
    5.90
    %
    
    13,851
    
    
    13,851
    
    
    --
    
    
    --
    
    
    --Due
      2030-2034
    
    --
    
    
    --
    
    
    --
    
    
    2.01
    %
    
    81,600
    
    
    51,100
    
    
    3.90
    %
    
    90,950
    
    
    --Total-Toledo
      Edison
    
    
    
    
    --
    
    
    145,000
    
    
    
    
    
    291,751
    
    
    309,451
    
    
    
    
    
    90,950
    
    
    85,250
    
    
    382,701
    
    
    539,701Pennsylvania
      Power Co.-Due
      2004-2009
    
    9.74
    %
    
    4,870
    
    
    40,344
    
    
    --
    
    
    --
    
    
    10,300
    
    
    --
    
    
    --
    
    
    19,700Due
      2010-2014
    
    9.74
    %
    
    4,870
    
    
    4,870
    
    
    5.40
    %
    
    1,000
    
    
    1,000
    
    
    --
    
    
    --
    
    
    --Due
      2015-2019
    
    9.74
    %
    
    4,903
    
    
    4,903
    
    
    4.24
    %
    
    45,325
    
    
    45,325
    
    
    --
    
    
    --
    
    
    --Due
      2020-2024
    
    7.63
    %
    
    6,500
    
    
    33,750
    
    
    3.94
    %
    
    27,182
    
    
    27,182
    
    
    --
    
    
    --
    
    
    --Due
      2025-2029
    
    --
    
    
    --
    
    
    --
    
    
    4.93
    %
    
    33,472
    
    
    23,172
    
    
    3.38
    %
    
    14,500
    
    
    --Due
      2030-2034
    
    --
    
    
    --
    
    
    --
    
    
    2.04
    %
    
    5,200
    
    
    --
    
    
    --
    
    
    --
    
    
    --Total-Penn
      Power
    
    
    
    
    21,143
    
    
    83,867
    
    
    
    
    
    112,179
    
    
    106,979
    
    
    
    
    
    14,500
    
    
    19,700
    
    
    147,822
    
    
    210,546Jersey
      Central Power & Light Co.-Due
      2004-2009
    
    6.89
    %
    
    45,985
    
    
    256,300
    
    
    5.79
    %
    
    240,391
    
    
    255,980
    
    
    --
    
    
    --
    
    
    124Due
      2010-2014
    
    --
    
    
    --
    
    
    --
    
    
    5.84
    %
    
    117,735
    
    
    117,735
    
    
    --
    
    
    --
    
    
    155Due
      2015-2019
    
    7.10
    %
    
    12,200
    
    
    12,200
    
    
    5.46
    %
    
    522,486
    
    
    222,486
    
    
    --
    
    
    --
    
    
    224Due
      2020-2024
    
    7.50
    %
    
    125,000
    
    
    205,000
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    325Due
      2025-2029
    
    7.18
    %
    
    200,000
    
    
    200,000
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    471Due
      2030-2034
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    682Due
      2035-2039
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    987Total-Jersey
      Central
    
    
    
    
    383,185
    
    
    673,500
    
    
    
    
    
    880,612
    
    
    596,201
    
    
    
    
    
    --
    
    
    2,968
    
    
    1,263,797
    
    
    1,272,669Metropolitan
      Edison Co.-Due
      2004-2009
    
    6.61
    %
    
    37,830
    
    
    128,265
    
    
    --
    
    
    --
    
    
    150,000
    
    
    5.79
    %
    
    150,000
    
    
    248Due
      2010-2014
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    250,000
    
    
    4.81
    %
    
    500,000
    
    
    310Due
      2015-2019
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    449Due
      2020-2024
    
    6.10
    %
    
    28,500
    
    
    28,500
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    650Due
      2025-2029
    
    5.95
    %
    
    13,690
    
    
    13,690
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    941Due
      2030-2034
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    1,364Due
      2035-2039
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    97,685Total-Metropolitan
      Edison
    
    
    
    
    80,020
    
    
    170,455
    
    
    
    
    
    --
    
    
    400,000
    
    
    
    
    
    650,000
    
    
    101,647
    
    
    730,020
    
    
    672,102








42





**FIRSTENERGY
CORP.**





**CONSOLIDATED
STATEMENTS OF CAPITALIZATION** (Cont’d)











****LONG-TERM
DEBT AND OTHER LONG-TERM OBLIGATIONS (Note
10(C))** ***(In
thousands)***
**(Interest
rates reflect weighted average rates)****


**FIRST
      MORTGAGE**
      **BONDS**
    
    
    
    **SECURED
      NOTES**
    
    
    
    **UNSECURED
      NOTES**
    
    **TOTAL****As
      of December 31,**
    **2004**
    
    **2003**
    
    
    
    **2004**
    
    **2003**
    
    
    
    **2004**
    
    **2003**
    
    **2004**
    
    **2003**Pennsylvania
      Electric Co.-Due
      2004-2009 6.12%
    $
    3,495
    
    $
    3,700
    
    
    --
    
    $
    --
    
    $
    --
    
    
    6.23
    %
    $
    108,000
    
    $
    233,124Due
      2010-2014 5.35%
    
    24,310
    
    
    24,310
    
    
    --
    
    
    --
    
    
    --
    
    
    5.63
    %
    
    185,000
    
    
    35,155Due
      2015-2019 --
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    6.63
    %
    
    125,000
    
    
    125,224Due
      2020-2024 5.80%
    
    20,000
    
    
    20,000
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    325Due
      2025-2029 6.05%
    
    25,000
    
    
    25,000
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    470Due
      2030-2034 --
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    682Due
      2035-2039 --
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    96,508Total-Pennsylvania
      Electric
    
    72,805
    
    
    73,010
    
    
    
    
    
    --
    
    
    --
    
    
    
    
    
    418,000
    
    
    491,488
    
    $
    490,805
    
    $
    564,498FirstEnergy
      Corp.-Due
      2004-2009 --
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    5.98
    %
    
    1,515,000
    
    
    1,570,000Due
      2010-2014 --
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    6.45
    %
    
    1,500,000
    
    
    1,500,000Due
      2030-2034 --
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    7.38
    %
    
    1,500,000
    
    
    1,500,000Total-FirstEnergy
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    
    
    
    4,515,000
    
    
    4,570,000
    
    
    4,515,000
    
    
    4,570,000Bay
      Shore Power
    
    --
    
    
    --
    
    
    6.24
    %
    
    137,500
    
    
    140,600
    
    
    --
    
    
    --
    
    
    --
    
    
    137,500
    
    
    140,600Facilities
      Services Group
    
    --
    
    
    --
    
    
    5.94
    %
    
    7,340
    
    
    7,754
    
    
    --
    
    
    --
    
    
    --
    
    
    7,340
    
    
    7,754FirstEnergy
      Generation
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    5.00
    %
    
    15,000
    
    
    15,000
    
    
    15,000
    
    
    15,000FirstEnergy
      Properties
    
    --
    
    
    --
    
    
    7.89
    %
    
    9,182
    
    
    9,438
    
    
    --
    
    
    --
    
    
    --
    
    
    9,182
    
    
    9,438Warrenton
      River Terminal
    
    --
    
    
    --
    
    
    6.00
    %
    
    220
    
    
    410
    
    
    --
    
    
    --
    
    
    --
    
    
    220
    
    
    410First
      Communications
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    6.26
    %
    
    5,000
    
    
    5,407
    
    
    5,000
    
    
    5,407Total
    
    762,153
    
    
    1,350,832
    
    
    
    
    
    3,398,947
    
    
    3,642,941
    
    
    
    
    
    6,728,943
    
    
    6,477,678
    
    
    10,890,043
    
    
    11,471,451Preferred
      stock subject to mandatory
      redemption
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    16,759
    
    
    18,514Capital
      lease obligations
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    10,732
    
    
    13,313Net
      unamortized premium on debt
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    36,759
    
    
    39,985Long-term
      debt due within one year
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (940,944
    )
    
    (1,754,197
    )Total
      long-term debt and other
      long-term
      obligations
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    10,013,349
    
    
    9,789,066TOTAL
      CAPITALIZATION
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    18,937,766
    
    $
    18,413,530





The accompanying
Notes to Consolidated Financial Statements are an integral part of these
statements.













43





**FIRSTENERGY
CORP.**





**CONSOLIDATED
STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY**






****
    ****
    ****
    ****
    ****
    ****
    ****
    ****
    **Accumulated**
    ****
    ****
    ****
    **Unallocated**
    ********
    ****
    ****
    ****
    ****
    ****
    ****
    ****
    **Other**
    ****
    **Other**
    ****
    ****
    ****
    **ESOP**
    ********
    ****
    **Comprehensive**
    ****
    **Number**
    ****
    **Par**
    ****
    **Paid-In**
    ****
    **Comprehensive**
    ****
    **Retained**
    ****
    **Common**
    ********
    ****
    **Income**
    ****
    **of
      Shares**
    ****
    **Value**
    ****
    **Capital**
    ****
    **Income
      (Loss)**
    ****
    **Earnings**
    ****
    **Stock**
    ********
    ****
    ***(Dollars
      in thousands)***Balance,
      January 1, 2002
    
    
    
    
    
    297,636,276
    
    $
    29,764
    
    $
    6,113,260
    
    $
    (169,003
    )
    $
    1,521,805
    
    $
    (97,227
    )Net
      income
    
    $
    552,804
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    552,804Minimum
      liability for unfunded retirementbenefits,
      net of $(316,681,000) ofincome
      taxes
    
    
    (449,615
    )
    
    
    
    
    
    
    
    
    
    
    (449,615
    )Unrealized
      gain on derivative hedges, netof
      $37,458,000 of income taxes
    
    
    59,187
    
    
    
    
    
    
    
    
    
    
    
    59,187Unrealized
      loss on investments, net of$(3,796,000)
      of income taxes
    
    
    (5,269
    )
    
    
    
    
    
    
    
    
    
    
    (5,269
    )Currency
      translation adjustments
    
    
    (91,448
    )
    
    
    
    
    
    
    
    
    
    
    (91,448
    )Comprehensive
      income
    
    $
    65,659Stock
      options exercised
    
    
    
    
    
    
    
    
    
    
    
    (8,169
    )Allocation
      of ESOP shares
    
    
    
    
    
    
    
    
    
    
    
    15,250
    
    
    
    
    
    
    
    
    18,950Cash
      dividends on common stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (439,628
    )Balance,
      December 31, 2002
    
    
    
    
    
    297,636,276
    
    
    29,764
    
    
    6,120,341
    
    
    (656,148
    )
    
    1,634,981
    
    
    (78,277
    )Net
      income
    
    $
    422,764
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    422,764Minimum
      liability for unfunded retirementbenefits,
      net of $101,950,000 ofincome
      taxes
    
    
    144,236
    
    
    
    
    
    
    
    
    
    
    
    144,236Unrealized
      loss on derivative hedges, netof
      $(241,000) of income taxes
    
    
    (347
    )
    
    
    
    
    
    
    
    
    
    
    (347
    )Unrealized
      gain on investments, net of$53,431,000
      of income taxes
    
    
    68,162
    
    
    
    
    
    
    
    
    
    
    
    68,162Currency
      translation adjustments
    
    
    91,448
    
    
    
    
    
    
    
    
    
    
    
    91,448Comprehensive
      income
    
    $
    726,263Stock
      options exercised
    
    
    
    
    
    
    
    
    
    
    
    (3,502
    )Common
      stock issued
    
    
    
    
    
    32,200,000
    
    
    3,220
    
    
    930,918Allocation
      of ESOP shares
    
    
    
    
    
    
    
    
    
    
    
    15,068
    
    
    
    
    
    
    
    
    20,073Cash
      dividends on common stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (453,360
    )Balance,
      December 31, 2003
    
    
    
    
    
    329,836,276
    
    
    32,984
    
    
    7,062,825
    
    
    (352,649
    )
    
    1,604,385
    
    
    (58,204
    )Net
      income
    
    $
    878,175
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    878,175Minimum
      liability for unfunded retirementbenefits,
      net of $(4,698,000) ofincome
      taxes
    
    
    (6,256
    )
    
    
    
    
    
    
    
    
    
    
    (6,256
    )Unrealized
      gain on derivative hedges, netof
      $9,638,000 of income taxes
    
    
    19,031
    
    
    
    
    
    
    
    
    
    
    
    19,031Unrealized
      gain on investments, net of$19,783,000
      of income taxes
    
    
    26,762
    
    
    
    
    
    
    
    
    
    
    
    26,762Comprehensive
      income
    
    $
    917,712Stock
      options exercised
    
    
    
    
    
    
    
    
    
    
    
    (24,174
    )Allocation
      of ESOP shares
    
    
    
    
    
    
    
    
    
    
    
    17,025
    
    
    
    
    
    
    
    
    15,087Common
      stock dividends declared in 2004payable
      in 2005
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (135,168
    )Cash
      dividends on common stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (490,529
    )Balance,
      December 31, 2004
    
    
    
    
    
    329,836,276
    
    $
    32,984
    
    $
    7,055,676
    
    $
    (313,112
    )
    $
    1,856,863
    
    $
    (43,117
    )


The accompanying
Notes to Consolidated Financial Statements are an integral part of these
statements.








44





**CONSOLIDATED
STATEMENTS OF PREFERRED STOCK**





**Not
      Subject to**
    
    **Subject
      to****Mandatory
      Redemption**
    
    **Mandatory
      Redemption****Par
      or**
    
    
    
    **Par
      or****Number**
    
    **Stated**
    
    **Number**
    
    **Stated****of
      Shares**
    
    **Value**
    
    **of
      Shares**
    
    **Value*****(Dollars
      in thousands)***Balance,
      January 1, 2002
    
    12,449,699
    
    $
    661,044
    
    
    22,552,751
    
    $
    624,449Redemptions-7.75%
      Series
    
    (4,000,000
    )
    
    (100,000
    )$7.56 Series
      B
    
    (450,000
    )
    
    (45,071
    )$42.40 Series
      T
    
    (200,000
    )
    
    (96,850
    )$8.32
      Series
    
    (100,000
    )
    
    (10,000
    )$7.76
      Series
    
    (150,000
    )
    
    (15,000
    )$7.80
      Series
    
    (150,000
    )
    
    (15,000
    )$10.00
      Series
    
    (190,000
    )
    
    (19,000
    )$2.21
      Series
    
    (1,000,000
    )
    
    (25,000
    )7.625%
      Series
    
    
    
    
    
    
    
    (7,500
    )
    
    (750
    )$7.35 Series
      C
    
    
    
    
    
    
    
    (10,000
    )
    
    (1,000
    )$90.00 Series
      S
    
    
    
    
    
    
    
    (17,750
    )
    
    (17,010
    )8.65% Series
      J
    
    
    
    
    
    
    
    (250,001
    )
    
    (26,750
    )7.52% Series
      K
    
    
    
    
    
    
    
    (265,000
    )
    
    (28,951
    )9.00%
      Series
    
    
    
    
    
    
    
    (4,800,000
    )
    
    (120,000
    )Amortization
      of fair marketvalue
      adjustments-$ 7.35 Series
      C
    
    
    
    
    
    
    
    
    
    
    (9
    )$90.00 Series
      S
    
    
    
    
    
    
    
    
    
    
    (258
    )8.56%
      Series
    
    
    
    
    
    
    
    
    
    
    (6
    )7.35%
      Series
    
    
    
    
    
    
    
    
    
    
    2097.34%
      Series
    
    
    
    
    
    
    
    
    
    
    214Balance,
      December 31, 2002
    
    6,209,699
    
    
    335,123
    
    
    17,202,500
    
    
    430,138Redemptions-7.625%
      Series
    
    
    
    
    
    
    
    (7,500
    )
    
    (750
    )$7.35 Series
      C
    
    
    
    
    
    
    
    (10,000
    )
    
    (1,000
    )8.56%
      Series
    
    
    
    
    
    
    
    (5,000,000
    )
    
    (125,242
    )FIN 46
      Deconsolidation-9.00%
      Series
    
    
    
    
    
    
    
    (4,000,000
    )
    
    (100,000
    )7.35%
      Series
    
    
    
    
    
    
    
    (4,000,000
    )
    
    (92,618
    )7.34%
      Series
    
    
    
    
    
    
    
    (4,000,000
    )
    
    (92,428
    )Amortization
      of fair marketvalue
      adjustments-$ 7.35 Series
      C
    
    
    
    
    
    
    
    
    
    
    (7
    )8.56%
      Series
    
    
    
    
    
    
    
    
    
    
    (2
    )7.35%
      Series
    
    
    
    
    
    
    
    
    
    
    2097.34%
      Series
    
    
    
    
    
    
    
    
    
    
    214Balance,
      December 31, 2003
    
    6,209,699
    
    $
    335,123
    
    
    185,000
    
    
    18,514
    *Redemptions-7.625%
      Series
    
    
    
    
    
    
    
    (7,500
    )
    
    (750
    )$7.35 Series
      C
    
    
    
    
    
    
    
    (10,000
    )
    
    (1,000
    )Amortization
      of fair marketvalue
      adjustments-$7.35 Series
      C
    
    
    
    
    
    
    
    
    
    
    (5
    )Balance,
      December 31, 2004
    
    6,209,699
    
    $
    335,123
    
    
    167,500
    
    $
    16,759
    *








*
    The December
      31, 2003 and 2004 balances for Preferred Stock subject to mandatory
      redemption are classifed as debt under SFAS
150.








The accompanying
Notes to Consolidated Financial Statements are an integral part of these
statements.










45





**FIRSTENERGY
CORP.**





**CONSOLIDATED
STATEMENTS OF CASH FLOWS**





**For
      the Years Ended December 31,**
    **2004**
    
    **2003**
    
    **2002*****(In
      thousands)*****CASH
      FLOWS FROM OPERATING ACTIVITIES:**Net
      Income
    $
    878,175
    
    $
    422,764
    
    $
    552,804Adjustments
      to reconcile net income to netcash
      from operating activities:Provision
      for depreciation
    
    589,652
    
    
    606,436
    
    
    721,493Amortization
      of regulatory assets
    
    1,166,323
    
    
    1,079,337
    
    
    940,991Deferral
      of new regulatory assets
    
    (256,795
    )
    
    (194,261
    )
    
    (183,947
    )Nuclear
      fuel and lease amortization
    
    96,084
    
    
    66,072
    
    
    80,507Other
      amortization, net
    
    (19,436
    )
    
    (16,278
    )
    
    (16,593
    )Deferred
      purchased power and other costs
    
    (416,617
    )
    
    (427,092
    )
    
    (543,644
    )Deferred
      income taxes and investment tax credits, net
    
    258,263
    
    
    53,639
    
    
    76,786Goodwill
      impairment (Note 2(H))
    
    36,471
    
    
    116,988
    
    
    --Disallowed
      regulatory assets
    
    --
    
    
    152,500
    
    
    --Investment
      impairments (Note 2(H))
    
    17,897
    
    
    43,803
    
    
    50,000Cumulative
      effect of accounting change
    
    --
    
    
    (174,663
    )
    
    --Deferred
      rents and lease market valuation liability
    
    (84,696
    )
    
    (119,398
    )
    
    (84,800
    )Revenue
      credits to customers
    
    --
    
    
    (71,984
    )
    
    (43,016
    )Accrued
      retirement benefit obligations
    
    137,742
    
    
    287,112
    
    
    124,678Accrued
      compensation, net
    
    18,397
    
    
    (84,503
    )
    
    (92,197
    )Tax
      refund related to pre-merger period
    
    --
    
    
    51,073
    
    
    --Commodity
      derivative transactions, net
    
    (48,840
    )
    
    (70,498
    )
    
    (8,682
    )Loss
      (income) from discontinued operations (Note 2(J))
    
    (4,396
    )
    
    103,632
    
    
    65,581Pension
      trust contribution
    
    (500,000
    )
    
    --
    
    
    --Decrease
      (increase) in operating assets:Receivables
    
    154,053
    
    
    66,311
    
    
    (73,392
    )Materials
      and supplies
    
    (36,751
    )
    
    5,399
    
    
    (29,134
    )Prepayments
      and other current assets
    
    47,010
    
    
    (31,155
    )
    
    133,677Increase
      (decrease) in operating liabilities:Accounts
      payable
    
    (110,947
    )
    
    (169,652
    )
    
    218,226Accrued
      taxes
    
    (15,011
    )
    
    221,500
    
    
    25,183Accrued
      interest
    
    (41,656
    )
    
    (59,782
    )
    
    (29,693
    )NUG
      power contract restructuring
    
    52,800
    
    
    --
    
    
    --Other
    
    (40,872
    )
    
    (102,445
    )
    
    47,466Net
      cash provided from operating activities
    
    1,876,850
    
    
    1,754,855
    
    
    1,932,294**CASH
      FLOWS FROM FINANCING ACTIVITIES:**New
      Financing-Common
      stock
    
    --
    
    
    934,138
    
    
    --Long-term
      debt
    
    961,474
    
    
    1,027,312
    
    
    668,676Short-term
      borrowings, net
    
    --
    
    
    --
    
    
    478,520Redemptions
      and Repayments-Preferred
      stock
    
    (1,750
    )
    
    (127,087
    )
    
    (522,223
    )Long-term
      debt
    
    (1,572,080
    )
    
    (2,128,567
    )
    
    (1,308,814
    )Short-term
      borrowings, net
    
    (351,051
    )
    
    (575,391
    )
    
    --Net
      controlled disbursement activity
    
    (2,740
    )
    
    24,689
    
    
    (14,083
    )Common
      stock dividend payments
    
    (490,529
    )
    
    (453,360
    )
    
    (439,628
    )Net
      cash used for financing activities
    
    (1,456,676
    )
    
    (1,298,266
    )
    
    (1,137,552
    )**CASH
      FLOWS FROM INVESTING ACTIVITIES:**Property
      additions
    
    (846,221
    )
    
    (856,316
    )
    
    (997,723
    )Proceeds
      from asset sales
    
    214,258
    
    
    78,743
    
    
    155,034Proceeds
      from certificates of deposit
    
    277,763
    
    
    --
    
    
    --Nonutility
      generation trusts withdrawals (contributions)
    
    (50,614
    )
    
    66,327
    
    
    49,044Contributions
      to nuclear decommissioning trusts
    
    (101,483
    )
    
    (101,218
    )
    
    (103,143
    )Avon
      cash and cash equivalents (Note 8)
    
    --
    
    
    --
    
    
    31,326Net
      assets held for sale
    
    --
    
    
    --
    
    
    (31,326
    )Long-term
      note receivable
    
    --
    
    
    82,250
    
    
    (91,335
    )Cash
      investments (Note 5)
    
    27,082
    
    
    52,884
    
    
    81,349Asset
      retirements and transfers
    
    9,513
    
    
    37,580
    
    
    29,619Other
      investments
    
    (7,993
    )
    
    29,137
    
    
    (7,944
    )Other
    
    (3,513
    )
    
    42,067
    
    
    52,397Net
      cash used for investing activities
    
    (481,208
    )
    
    (568,546
    )
    
    (832,702
    )Net
      decrease in cash and cash equivalents
    
    (61,034)
    
    
    (111,957)
    
    
    (37,960)Cash
      and cash equivalents at beginning of year
    
    113,975
    
    
    225,932
    
    
    263,892Cash
      and cash equivalents at end of year
    $
    52,941
    
    $
    113,975
    
    $
    225,932**SUPPLEMENTAL
      CASH FLOWS INFORMATION:**Cash
      Paid During the Year-Interest
      (net of amounts capitalized)
    $
    704,067
    
    $
    730,277
    
    $
    881,515Income
      taxes
    $
    512,419
    
    $
    161,915
    
    $
    389,180








The
accompanying Notes to Consolidated Financial Statements are an integral part of
these statements.





46





**FIRSTENERGY
CORP.**





**CONSOLIDATED
STATEMENTS OF TAXES**





**For
      the Years Ended December 31,**
    **2004**
    
    **2003**
    
    **2002*****(In
      thousands)*****GENERAL
      TAXES:**Kilowatt-hour
      excise*
    $
    236,398
    
    $
    228,216
    
    $
    219,970State gross
      receipts*
    
    139,616
    
    
    130,244
    
    
    132,622Real and
      personal property
    
    207,504
    
    
    183,694
    
    
    218,683Social
      security and unemployment
    
    75,898
    
    
    68,019
    
    
    46,345Other
    
    18,436
    
    
    28,292
    
    
    32,709Total general
      taxes
    $
    677,852
    
    $
    638,465
    
    $
    650,329**PROVISION
      FOR INCOME TAXES:**Currently
      payable**-**Federal
    $
    283,341
    
    $
    306,347
    
    $
    326,417State
    
    132,356
    
    
    118,155
    
    
    104,867Foreign
    
    --
    
    
    (1,165
    )
    
    20,624415,697
    
    
    423,337
    
    
    451,908Deferred,
      net**-**Federal
    
    245,967
    
    
    71,910
    
    
    81,934State
    
    38,968
    
    
    8,133
    
    
    7,759Foreign
    
    --
    
    
    --
    
    
    13,600284,935
    
    
    80,043
    
    
    103,293Investment
      tax credit amortization
    
    (26,672
    )
    
    (26,404
    )
    
    (26,507
    )Total
      provision for income taxes
    $
    673,960
    
    $
    476,976
    
    $
    528,694**RECONCILIATION
      OF FEDERAL INCOME TAX EXPENSE AT****STATUTORY
      RATE TO TOTAL PROVISION FOR INCOME TAXES:**Book income
      before provision for income taxes
    $
    1,552,135
    
    $
    899,740
    
    $
    1,081,498Federal
      income tax expense at statutory rate
    $
    543,247
    
    $
    314,909
    
    $
    378,524Increases
      (reductions) in taxes resulting from-Amortization
      of investment tax credits
    
    (26,672
    )
    
    (26,404
    )
    
    (26,507
    )State income
      taxes, net of federal income tax benefit
    
    111,361
    
    
    82,088
    
    
    73,207Amortization
      of tax regulatory assets
    
    32,683
    
    
    31,909
    
    
    29,296Preferred
      stock dividends
    
    7,495
    
    
    7,202
    
    
    13,634Reserve for
      foreign operations
    
    --
    
    
    44,305
    
    
    48,587Other,
      net
    
    5,846
    
    
    22,967
    
    
    11,953Total
      provision for income taxes
    $
    673,960
    
    $
    476,976
    
    $
    528,694**ACCUMULATED
      DEFERRED INCOME TAXES AT DECEMBER 31:**Property
      basis differences
    $
    2,451,213
    
    $
    2,293,209
    
    $
    2,052,594Regulatory
      transition charge
    
    785,312
    
    
    1,084,871
    
    
    1,408,232Customer
      receivables for future income taxes
    
    103,149
    
    
    139,335
    
    
    144,073Deferred sale
      and leaseback costs
    
    (92,417
    )
    
    (95,474
    )
    
    (99,647
    )Nonutility
      generation costs
    
    (174,174
    )
    
    (221,063
    )
    
    (228,476
    )Unamortized
      investment tax credits
    
    (61,267
    )
    
    (70,054
    )
    
    (78,227
    )Other
      comprehensive income
    
    (219,020
    )
    
    (243,743
    )
    
    (398,883
    )Lease market
      valuation liability
    
    (420,078
    )
    
    (455,074
    )
    
    (490,698
    )Retirement
      Benefits
    
    (185,573
    )
    
    (359,038
    )
    
    (223,065
    )Oyster Creek
      securitization (Note 10(C))
    
    184,245
    
    
    193,558
    
    
    202,447Loss
      carryforwards
    
    (463,106
    )
    
    (495,254
    )
    
    (507,690
    )Loss
      carryforward valuation reserve
    
    419,978
    
    
    470,813
    
    
    482,061Purchase
      accounting basis differences
    
    (2,657
    )
    
    (2,657
    )
    
    (2,657
    )Sale of
      generating assets
    
    (9,539
    )
    
    (11,785
    )
    
    (11,786
    )Provision for
      rate refund
    
    --
    
    
    --
    
    
    (29,370
    )All
      other
    
    8,031
    
    
    (49,569
    )
    
    (149,226
    )Net deferred
      income tax liability
    $
    2,324,097
    
    $
    2,178,075
    
    $
    2,069,682





*  Collected from
customers through regulated rates and included in revenue on the Consolidated
Statements of Income.





The accompanying
Notes to Consolidated Financial Statements are an integral part of these
statements.





47





**NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS**





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





FirstEnergy's
principal business 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. FirstEnergy’s consolidated financial statements
also include its other 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, the PUCO, PPUC and
NJBPU. The preparation of financial statements in conformity with GAAP requires
management to make periodic estimates and assumptions that affect the reported
amounts of assets, liabilities, revenues and expenses and the disclosure of
contingent assets and liabilities. Actual results could differ from these
estimates.





FirstEnergy
consolidates all majority-owned subsidiaries over which the Company exercises
control and, when applicable, entities for which the Company has a controlling
financial interest. Intercompany transactions and balances are eliminated in
consolidation. Investments in nonconsolidated affiliates (20-50 percent owned
companies, joint ventures and partnerships) over which the Company has the
ability to exercise significant influence, but not control, are accounted for on
the equity basis.





Certain prior year
amounts have been reclassified to conform to the current year presentation. Revenue amounts
related to transmission activities previously recorded as wholesale electric
sales revenues were reclassified as transmission revenues.  Expenses  (including
transmission and congestion charges) were reclassified among purchased power,
other operating costs and amortization of regulatory assets to conform to the
current year presentation of generation commodity costs. FES' natural gas
business has been classified as discontinued operations on the Consolidated
Statements of Income (See Note 2(J)). As discussed in Note 14, segment reporting
in 2003 and 2002 was reclassified to conform to the 2004 business segment
organization and operations.





Unless otherwise
indicated, defined terms used herein have the meanings set forth in the
accompanying Glossary of Terms.





**2.**
    **SUMMARY
      OF SIGNIFICANT ACCOUNTING POLICIES**





**(A)**
    **ACCOUNTING
      FOR THE EFFECTS OF REGULATION**





FirstEnergy
accounts for the effects of regulation through the application of SFAS 71 to its
operating utilities when their rates:





·
    are
      established by a third-party regulator with the authority to set rates
      that bind customers;·
    are
      cost-based; and·
    can be
      charged to and collected from customers.


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





48





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





·
    restructuring
      the electric generation business and allowing the Companies' customers to
      select a competitive
      electric
      generation supplier other than the Companies;·
    establishing
      or defining the PLR obligations to customers in the Companies' service
      areas;·
    providing the
      Companies with the opportunity to recover 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;·
    continuing
      regulation of the Companies' transmission and distribution systems;
      and·
    requiring
      corporate separation of regulated and unregulated business
      activities.





**Regulatory
Assets**





The EUOC recognize,
as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU have authorized
for recovery from customers in future periods or for which authorization is
probable. Without the probability of such authorization, costs currently
recorded as regulatory assets would have been charged to income as incurred. All
regulatory assets are expected to be recovered from customers under the
Companies' respective transition and regulatory plans. Based on those plans, the
Companies continue to bill and collect cost-based rates for their transmission
and distribution services, which remain regulated; accordingly, it is
appropriate that the Companies continue the application of SFAS 71 to those
operations. Regulatory assets that do not earn a current return totaled
approximately $240 million as of December 31, 2004.





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





**2004**
    
    **2003*****(In
      millions)***Regulatory
      transition costs
    
    $
    4,889
    
    $
    6,427Customer
      shopping incentives
    
    
    612
    
    
    371Customer
      receivables for future income taxes
    
    
    246
    
    
    340Societal
      benefits charge
    
    
    51
    
    
    81Loss on
      reacquired debt
    
    
    89
    
    
    75Employee
      postretirement benefit costs
    
    
    65
    
    
    77Nuclear
      decommissioning, decontaminationand spent
      fuel disposal costs
    
    
    (169
    )
    
    (96
    )Asset removal
      costs
    
    
    (340
    )
    
    (321
    )Property
      losses and unrecovered plant costs
    
    
    50
    
    
    70Other
    
    
    39
    
    
    53Total
    
    $
    5,532
    
    $
    7,077





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 (OE - $228 million, CEI - $295 million, TE - $89 million, as
of December 31, 2004) 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 during that period. OE, TE and CEI expect to
recover these deferred customer shopping incentives by August 31, 2008,
September 30, 2008 and August 31, 2010, respectively.





49





**Transition
Cost Amortization**





OE, CEI and TE
amortize transition costs (see Regulatory Matters - Ohio) using the effective
interest method. Under the Rate Stabilization Plan, total transition cost
amortization is expected to approximate the following for 2005 through 2009.





**FirstEnergy**
    
    **OE**
    
    **CEI**
    
    **TE*****(In
      millions)***2005
    
    $
    828
    
    $
    467
    
    $
    222
    
    $
    1392006
    
    
    404
    
    
    193
    
    
    126
    
    
    852007
    
    
    327
    
    
    93
    
    
    139
    
    
    952008
    
    
    159
    
    
    --
    
    
    159
    
    
    --2009
    
    
    54
    
    
    --
    
    
    54
    
    
    --








The decrease in
amortization beginning in 2006 results from the termination of
generation-related transition cost recovery under the Ohio transition
plan.





Regulatory
transition costs as of December 31, 2004 for JCP&L, Met-Ed and Penelec are
approximately $2.2 billion, $0.7 billion and $0.1 billion, respectively.
Deferral of above-market costs from power supplied by NUGs to JCP&L are
approximately $1.2 billion and are being recovered through BGS and MTC revenues.
Met-Ed and Penelec have deferred above-market NUG costs totaling approximately
$0.5 billion and $0.1 billion, respectively. These costs are being recovered
through CTC revenues. The regulatory asset for above-market NUG costs and a
corresponding liability are adjusted to fair value at the end of each quarter.
Recovery of the remaining regulatory transition costs is expected to continue
under the provisions of the various regulatory proceedings for New Jersey and
Pennsylvania discussed in Note 9.





**Accounting
for Generation Operations**





The application of
SFAS 71 was discontinued prior to 2001 with respect to the Companies' generation
operations. The SEC's interpretive guidance regarding asset impairment
measurement provided that any supplemental regulated cash flows such as a CTC
should be excluded from the cash flows of assets in a portion of the business
not subject to regulatory accounting practices. If those assets are impaired, a
regulatory asset should be established if the costs are recoverable through
regulatory cash flows. Consistent with the SEC guidance and EITF 97-4, $1.8
billion of impaired plant investments ($1.2 billion, $227 million, $304 million
and $53 million for OE, Penn, CEI and TE, respectively) were recognized as
regulatory assets recoverable as transition costs through future regulatory cash
flows. The following summarizes net assets included in property, plant and
equipment relating to operations for which the application of SFAS 71 was
discontinued, compared with the respective company's total assets as of
December 31, 2004.





**SFAS
      71****Discontinued****Net
      Assets**
    
    **Total
      Assets*****(In
      millions)***OE
    
    $
    1,059
    
    $
    5,814CEI
    
    
    1,263
    
    
    6,690TE
    
    
    652
    
    
    2,834Penn
    
    
    263
    
    
    921JCP&L
    
    
    39
    
    
    7,291Met-Ed
    
    
    13
    
    
    3,245








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





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





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





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





50


Receivables from
customers include sales to residential, commercial and industrial customers and
sales to wholesale customers. There was no material concentration of receivables
as of December 31, 2004 or 2003, with respect to any particular segment of
FirstEnergy's customers. Total customer receivables were $979 million (billed -
$672 million and unbilled - $307 million) and $1.0 billion (billed - $664
million and unbilled - $336 million) as of December 31, 2004 and 2003,
respectively.




Other receivables
include amounts due from customers for unregulated sales and CEI's retained
interest in customer receivables sold to CFC (see Note 12).





**(D)**
    **ACCOUNTING
      FOR CERTAIN WHOLESALE ENERGY
TRANSACTIONS**





FES engages in
purchase and sale transactions in the PJM Market to support the supply of
end-use customers, including its BGS obligation in New Jersey and PLR
requirements in Pennsylvania. FES meets its supply commitments by transmitting
energy into the PJM control area and through bilateral purchased power contracts
with counterparties in PJM. FES schedules purchase and sale transactions for
each hour in PJM on a day-ahead basis with system balancing occurring real-time.
FES sells energy to the PJM Market at the location of its supply (transmitted
and contracted energy) and purchases energy from the PJM Market at the location
of its demand (end-use customer load).





FES accounts for
energy transactions in the PJM Market in accordance with EITF 99-19, recognizing
purchases and sales on a gross basis by recording each discrete transaction.
This presentation may not be comparable to other energy companies that have
dedicated generating capacity in ISOs or fail to meet the criteria for gross
presentation in EITF 99-19.





FES' purchase and
sale transactions in the PJM Market for the three years ended December 31,
2004 are summarized as follows:








**2004**
    **2003**
    **2002*****(In
      millions)***Sales
    $
      1,182
    $ 665
    $
      272Purchases
    1,107
    826
    376








**(E)**
    **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.
In 2004, 2003 and 2002, stock-based awards to purchase shares of common stock
totaling 0.1 million, 3.3 million and 3.4 million, respectively, were excluded
from the calculation of diluted earnings per share of common stock because their
exercise prices were greater than the average market price of common shares
during the period. The following table reconciles the denominators for basic and
diluted earnings per share from Income Before Discontinued Operations and
Cumulative Effect of Accounting Change:








**Reconciliation
      of Basic and****Diluted
      Earnings per Share**
    **2004**
    **2003**
    **2002*****(In
      thousands)***Income Before
      Discontinued Operations andCumulative
      Effect of Accounting Change
    $873,779
    $424,249
    $618,385Average
      Shares of Common Stock Outstanding:Denominator
      for basic earnings per share(weighted
      average shares outstanding)
    327,387
    303,582
    293,194Assumed
      exercise of dilutive stock options and awards
    1,595
    1,390
    1,227Denominator
      for diluted earnings per share
    328,982
    304,972
    294,421Income Before
      Discontinued Operations and CumulativeEffect of
      Accounting Change, per common share:Basic
    $2.67
    $1.40
    $2.11Diluted
    $2.66
    $1.40
    $2.10








51





**(F)**
    **PROPERTY,
      PLANT AND EQUIPMENT**





Property, plant and
equipment reflects original cost (except for nuclear generating assets which
were adjusted to fair value), including payroll and related costs such as taxes,
employee benefits, administrative and general costs, and interest costs incurred
to place the assets in service. The costs of normal maintenance, repairs and
minor replacements are expensed as incurred. FirstEnergy's accounting policy for
planned major maintenance projects is to recognize liabilities as they are
incurred.





The Companies
provide for depreciation on a straight-line basis at various rates over the
estimated lives of property included in plant in service. The respective annual
composite rates for the Companies' electric plant in 2004, 2003 and 2002 are
shown in the following table:








**Annual
      Composite****Depreciation
      Rate****2004**
    
    **2003**
    
    **2002**OE
    
    
    2.3
    %
    
    2.2
    %
    
    2.4
    %CEI
    
    
    2.8
    
    
    2.8
    
    
    3.6TE
    
    
    2.8
    
    
    2.8
    
    
    3.8Penn
    
    
    2.2
    
    
    2.2
    
    
    2.3JCP&L
    
    
    2.1
    
    
    2.8
    
    
    3.5Met-Ed
    
    
    2.4
    
    
    2.6
    
    
    3.0Penelec
    
    
    2.5
    
    
    2.7
    
    
    3.0








*Jointly-Owned
Generating Stations*





JCP&L holds a
50 percent ownership interest in Yards Creek Pumped Storage Facility - its net
book value was approximately $19.2 million as of December 31, 2004. All
other generating units are owned and/or leased by the Companies individually or
together as tenants in common.





*Asset
Retirement Obligations*





FirstEnergy
recognizes a liability for retirement obligations associated with tangible
assets in accordance with SFAS 143. This standard requires recognition of the
fair value of a liability for an ARO in the period in which it is incurred. The
associated asset retirement costs are capitalized as part of the carrying value
of the long-lived asset and depreciated over time, as described further in Note
11, "Asset Retirement Obligations".





*Nuclear
Fuel*





Property, plant and
equipment includes nuclear fuel recorded at original cost, which includes
material, enrichment, fabrication and interest costs incurred prior to reactor
load. The Companies amortize the cost of nuclear fuel based on the units of
production method.





**(G)**
    **STOCK-BASED
      COMPENSATION**





FirstEnergy applies
the recognition and measurement principles of APB 25 and related Interpretations
in accounting for its stock-based compensation plans (see Note 4). No material
stock-based employee compensation expense is reflected in net income for options
as all options granted under those plans had an exercise price equal to the
market value of the underlying common stock on the grant date, resulting in
substantially no intrinsic value. FirstEnergy will apply the recognition and
measurement principles of SFAS 123R effective July 1, 2005 (see Note
15).





**(H)**
    **ASSET
      IMPAIRMENTS**





*Long-Lived
Assets*


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




52





*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 makes such evaluations more frequently if indicators of
impairment 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 its expected discounted future cash
flows.





FirstEnergy's 2004
annual review was completed in the third quarter of 2004 with no impairment
indicated. In December 2004,
the FSG subsidiaries qualified as held for sale in accordance with SFAS 144.
SFAS 142 requires the goodwill of a reporting unit to be tested for impairment
if there is a more-likely-than-not expectation that the reporting unit or a
significant asset group within the reporting unit will be sold. As required by
SFAS 142, the goodwill of FSG was tested for impairment, resulting in a non-cash
charge of $36 million in the fourth quarter of 2004. FSG's fair value was
estimated using current market valuations.





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. FirstEnergy's
goodwill primarily relates to its regulated services segment. In the year ended
December 31, 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 used to offset
capital gains generated in 2004. The impairment
analysis includes a significant source of cash representing the Companies'
recovery of transition costs as described in Note 9. FirstEnergy estimates that
completion of transition cost recovery will not result in an impairment of
goodwill relating to its regulated business segment.





A summary of the
changes in FirstEnergy's goodwill for the years ended December 31, 2004 and
2003 is shown below by segment (See Note 14 - Segment Information):








**Competitive****Electric****Regulated**
    
    **Energy**
    
    **Facilities****Services**
    
    **Services**
    
    **Services**
    
    **Other**
    
    **Consolidated****(In
      millions)**Balance as of
      January 1, 2003
    
    $
    5,993
    
    $
    24
    
    $
    196
    
    $
    65
    
    $
    6,278Impairment
      charges
    
    
    
    
    
    
    
    
    (122
    )
    
    
    
    
    (122
    )FSG
      divestitures
    
    
    
    
    
    
    
    
    (41
    )
    
    
    
    
    (41
    )Other
    
    
    
    
    
    
    
    
    3
    
    
    10
    
    
    13Balance as of
      December 31, 2003
    
    
    5,993
    
    
    24
    
    
    36
    
    
    75
    
    
    6,128Impairment
      charges
    
    
    
    
    
    
    
    
    (36
    )
    
    
    
    
    (36
    )Adjustments
      related to GPU acquisition
    
    
    (42
    )
    
    
    
    
    
    
    
    
    
    
    (42
    )Balance as of
      December 31, 2004
    
    $
    5,951
    
    $
    24
    
    $
    --
    
    $
    75
    
    $
    6,050








*Investments*





The Companies
periodically evaluate for impairment investments that include available-for-sale
securities held by their nuclear decommissioning trusts. In accordance with SFAS
115, securities classified as available-for-sale are evaluated to determine
whether a decline in fair value below the cost basis is other than temporary. If
the decline in fair value is determined to be other than temporary, the cost
basis of the security is written down to fair value. FirstEnergy considers,
among other factors, the length of time and the extent to which the security's
fair value has been less than cost and the near-term financial prospects of the
security issuer when evaluating investments for impairment. The fair value and
unrealized gains and losses of the Companies' investments are disclosed in Note
5.





53





**(I)**
    **COMPREHENSIVE
      INCOME**





Comprehensive
income includes net income as reported on the Consolidated Statements of Income
and all other changes in common stockholders' equity except those resulting from
transactions with common stockholders. As of December 31, 2004, AOCL
consisted of a minimum liability for unfunded retirement benefits of $312
million, unrealized gains on investments in securities available for sale of $91
million, and unrealized losses on derivative instrument hedges of $92 million.
As of December 31, 2003, AOCL consisted of a minimum liability for unfunded
retirement benefits of $306 million, unrealized gains on investments in
securities available for sale of $64 million, and unrealized losses on
derivative instrument hedges of $111 million. Other comprehensive income of $8
million was reclassified to net income in 2004, including an $8 million loss on
derivative instrument hedges ($5 million net of tax) and a $22 million gain on
available-for-sale securities ($13 million net of tax). Other comprehensive
income (loss) reclassified to net income in 2003 and 2002 totaled
$29 million and $(10) million, respectively. These amounts were net of
income taxes in 2003 and 2002 of $20 million and $(7) million,
respectively.





**(J)**
    **ASSETS
      HELD FOR SALE AND DISCONTINUED
OPERATIONS**





In December 2004,
the FSG subsidiaries qualified as held for sale in accordance with SFAS 144.
Management anticipates that the transfer of FSG assets, with a carrying value of
$57 million as of December 31, 2004, will qualify for recognition as
completed sales within one year. As required by SFAS 142, the goodwill of FSG
was tested for impairment, resulting in a non-cash charge of $36 million in the
fourth quarter of 2004 (See Note 2(H)). As of December 31, 2004, the FSG
subsidiaries classified as held for sale did not meet the criteria for
discontinued operations. The carrying amounts of FSG's assets and liabilities
held for sale are not material to and have not been classified as assets held
for sale on FirstEnergy's Consolidated Balance Sheets. See Note 14 for FSG's
segment financial information.





FES operates a
natural gas business with commercial and industrial customers in Ohio,
Pennsylvania and West Virginia. Sales requirements are sourced through a
combination of short-term and long-term supply agreements. In December 2004,
FES' natural gas business qualified as held for sale in accordance with SFAS
144. Management expects to complete the sale within one year. As required by
SFAS 142, goodwill associated with FES' natural gas business was tested for
impairment as of December 31, 2004 with no impairment indicated. Financial
results are included in discontinued operations on the Consolidated Statements
of Income and classified as "Other" in the segment financial information (See
Note 14). FES' natural gas purchases and sales for the three years ended
December 31, 2004 are summarized as follows:








**2004**
    
    **2003**
    
    **2002*****(In
      millions)***Natural gas
      sales
    
    $
    496
    
    $
    603
    
    $
    594Natural gas
      purchases
    
    
    480
    
    
    583
    
    
    544








In December 2003,
EGSA, GPU Power’s Bolivia subsidiary, was sold to Bolivia Integrated Energy
Limited. FirstEnergy included in discontinued operations a $33 million loss on
the sale of EGSA in the fourth quarter of 2003 (no income tax benefit was
realized) and an operating loss for the year of $2 million. Discontinued
operations in 2002 include EGSA's operating income of $10 million.





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. FirstEnergy included in discontinued
operations Emdersa's operating income of $11 million and a $67 million
charge for the abandonment in the second quarter of 2003 (no income tax benefit
was recognized). An after-tax loss of $87 million (including $109 million in
currency transaction losses arising principally from U.S. dollar denominated
debt) was included in discontinued operations in 2002.





The FSG
subsidiaries, Colonial Mechanical and Webb Technologies, were sold in January
2003 and Ancoma, Inc. was sold in December 2003. The MARBEL subsidiary, NEO was
sold in June 2003. The 2003 and 2002 operating results for these divested
businesses included in discontinued operations ("Other" in the table below) for
the years ended December 2003 and 2002 totaled $(6) million and $5 million,
respectively.





54





Revenues associated
with discontinued operations were $496 million, $655 million and $878 million
for 2004, 2003 and 2002, respectively. The following table summarizes the net
income (loss) included in "Discontinued Operations" on the Consolidated
Statements of Income for the three years ended December 31, 2004:








**2004**
    
    **2003**
    
    **2002*****(In
      millions)***FES' natural
      gas business
    
    $
    4
    
    $
    (2
    )
    $
    15EGSA
    
    
    --
    
    
    (35
    )
    
    5Emdersa
    
    
    --
    
    
    (60
    )
    
    (87
    )Other
    
    
    --
    
    
    (6
    )
    
    2Discontinued
      operations income (loss)
    
    $
    4
    
    $
    (103
    )
    $
    (65
    )








**(K)**
    **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 $0.33 per share of common stock
(basic and diluted) in the year ended December 31, 2003. Upon adoption of
the accounting standard, FirstEnergy reversed accrued nuclear plant
decommissioning costs of $1.24 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 subject to refund through rates related to the ARO for nuclear
decommissioning. The cumulative effect adjustment also included the reversal of
$60 million of accumulated estimated removal costs for non-regulated generation
assets.





**(L)**
    **INCOME
      TAXES**





Details of the
total provision for income taxes are shown on the Consolidated Statements of
Taxes. FirstEnergy records income taxes in accordance with the liability method
of accounting. Deferred income taxes reflect the net tax effect of temporary
differences between the carrying amounts of assets and liabilities for financial
reporting purposes and the amounts recognized for tax purposes. Investment tax
credits, which were deferred when utilized, are being amortized over the
recovery period of the related property. Deferred income tax liabilities related
to tax and accounting basis differences and tax credit carryforward items are
recognized at the statutory income tax rates in effect when the liabilities are
expected to be paid. Deferred tax assets are recognized based on income tax
rates expected to be in effect when they are settled.





FirstEnergy has
capital loss carryforwards of approximately $1.1 billion, most of which expire
in 2007. The deferred tax assets associated with these capital loss
carryforwards ($364 million) are fully offset by a valuation allowance as of
December 31, 2004, since management is unable to predict whether sufficient
capital gains will be generated to utilize all of these capital loss
carryforwards. Any ultimate utilization of capital loss carryforwards for which
valuation allowances were established through purchase accounting would adjust
goodwill.





The Company has
also recorded valuation allowances of $51 million for deferred tax assets
associated with impairment losses related to certain domestic assets and the
divestiture of international assets acquired through the merger with GPU (see
Note 8).





FirstEnergy has net
operating loss carryforwards for state and local income tax purposes of
approximately $884 million. A valuation allowance of $5 million has been
recorded against the associated deferred tax assets of $48 million. These
losses expire as follows:








**Expiration
      Period**
    
    **Amount*****(in
      millions)***2005-2009
    
    $
    2602010-2014
    
    
    462015-2019
    
    
    2172020-2023
    
    
    361$
    884








55





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





FirstEnergy
provides noncontributory defined benefit pension plans that cover substantially
all of its employees. The trusteed plans provide defined benefits based on years
of service and compensation levels. The Company's funding policy is based on
actuarial computations using the projected unit credit method. In the third
quarter of 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 was approximately $300
million.





FirstEnergy
provides a minimum amount of noncontributory life insurance to retired employees
in addition to optional contributory insurance. Health care benefits, which
include certain employee contributions, deductibles and copayments, are also
available to retired employees, their dependents and, under certain
circumstances, their survivors. The Company recognizes the expected cost of
providing other postretirement benefits to employees and their beneficiaries and
covered dependents from the time employees are hired until they become eligible
to receive those benefits.





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





56








**Obligations
      and Funded Status**
    
    **Pension
      Benefits**
    
    **Other
      Benefits****As of
      December 31**
    
    **2004**
    
    **2003**
    
    **2004**
    
    **2003*****(In
      millions)*****Change
      in benefit obligation**Benefit
      obligation as of January 1
    
    $
    4,162
    
    $
    3,866
    
    $
    2,368
    
    $
    2,077Service
      cost
    
    
    77
    
    
    66
    
    
    36
    
    
    43Interest
      cost
    
    
    252
    
    
    253
    
    
    112
    
    
    136Plan
      participants’ contributions
    
    
    --
    
    
    --
    
    
    14
    
    
    6Plan
      amendments
    
    
    --
    
    
    --
    
    
    (281
    )
    
    (123
    )Actuarial
      (gain) loss
    
    
    134
    
    
    222
    
    
    (211
    )
    
    323Benefits
      paid
    
    
    (261
    )
    
    (245
    )
    
    (108
    )
    
    (94
    )Benefit
      obligation as of December 31
    
    $
    4,364
    
    $
    4,162
    
    $
    1,930
    
    $
    2,368**Change
      in fair value of plan assets**Fair value of
      plan assets as of January 1
    
    $
    3,315
    
    $
    2,889
    
    $
    537
    
    $
    473Actual return
      on plan assets
    
    
    415
    
    
    671
    
    
    57
    
    
    88Company
      contribution
    
    
    500
    
    
    --
    
    
    64
    
    
    68Plan
      participants’ contribution
    
    
    --
    
    
    --
    
    
    14
    
    
    2Benefits
      paid
    
    
    (261
    )
    
    (245
    )
    
    (108
    )
    
    (94
    )Fair value of
      plan assets as of December 31
    
    $
    3,969
    
    $
    3,315
    
    $
    564
    
    $
    537**Funded
      status**
    
    $
    (395
    )
    $
    (847
    )
    $
    (1,366
    )
    $
    (1,831
    )Unrecognized
      net actuarial loss
    
    
    885
    
    
    919
    
    
    730
    
    
    994Unrecognized
      prior service cost (benefit)
    
    
    63
    
    
    72
    
    
    (378
    )
    
    (221
    )Unrecognized
      net transition obligation
    
    
    --
    
    
    --
    
    
    --
    
    
    83Net asset
      (liability) recognized
    
    $
    553
    
    $
    144
    
    $
    (1,014
    )
    $
    (975
    )**Amounts
      Recognized in the****Consolidated
      Balance Sheets****As of
      December 31**Accrued
      benefit cost
    
    $
    (14
    )
    $
    (438
    )
    $
    (1,014
    )
    $
    (975
    )Intangible
      assets
    
    
    63
    
    
    72
    
    
    --
    
    
    --Accumulated
      other comprehensive loss
    
    
    504
    
    
    510
    
    
    --
    
    
    --Net amount
      recognized
    
    $
    553
    
    $
    144
    
    $
    (1,014
    )
    $
    (975
    )Increase
      (decrease) in minimum liabilityincluded in
      other comprehensive income(net of
      tax)
    
    $
    (4
    )
    $
    (145
    )
    
    --
    
    
    --**Assumptions
      Used to Determine****Benefit
      Obligations As of December 31**Discount
      rate
    
    
    6.00
    %
    
    6.25
    %
    
    6.00
    %
    
    6.25
    %Rate of
      compensation increase
    
    
    3.50
    %
    
    3.50
    %**Allocation
      of Plan Assets****As of
      December 31**Asset
      CategoryEquity
      securities
    
    
    68
    %
    
    70
    %
    
    74
    %
    
    71
    %Debt
      securities
    
    
    29
    
    
    27
    
    
    25
    
    
    22Real
      estate
    
    
    2
    
    
    2
    
    
    --
    
    
    --Cash
    
    
    1
    
    
    1
    
    
    1
    
    
    7Total
    
    
    100
    %
    
    100
    %
    
    100
    %
    
    100
    %**Information
      for Pension Plans With an****Accumulated
      Benefit Obligation in****Excess
      of Plan Assets**
    
    
    **2004**
    
    
    **2003********
    
    ***(In
      millions)***Projected
      benefit obligation
    
    $
    4,364
    
    $
    4,162Accumulated
      benefit obligation
    
    
    3,983
    
    
    3,753Fair value of
      plan assets
    
    
    3,969
    
    
    3,315





57








**Pension
      Benefits**
    
    **Other
      Benefits****Components
      of Net Periodic Benefit Costs**
    
    **2004**
    
    **2003**
    
    **2002**
    
    **2004**
    
    **2003**
    
    **2002*****(In
      millions)***Service
      cost
    
    $
    77
    
    $
    66
    
    $
    59
    
    $
    36
    
    $
    43
    
    $
    29Interest
      cost
    
    
    252
    
    
    253
    
    
    249
    
    
    112
    
    
    137
    
    
    114Expected
      return on plan assets
    
    
    (286
    )
    
    (248
    )
    
    (346
    )
    
    (44
    )
    
    (43
    )
    
    (52
    )Amortization
      of prior service cost
    
    
    9
    
    
    9
    
    
    9
    
    
    (40
    )
    
    (9
    )
    
    3Amortization
      of transition obligation (asset)
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    9
    
    
    9Recognized
      net actuarial loss
    
    
    39
    
    
    62
    
    
    --
    
    
    39
    
    
    40
    
    
    11Net periodic
      cost (income)
    
    $
    91
    
    $
    142
    
    $
    (29
    )
    $
    103
    
    $
    177
    
    $
    114**Weighted-Average
      Assumptions Used****to
      Determine Net Periodic Benefit Cost**
    
    **Pension
      Benefits**
    **Other
      Benefits****for
      Years Ended December 31**
    
    
    **2004**
    
    
    **2003**
    
    
    **2002**
    
    
    **2004**
    
    
    **2003**
    
    
    **2002**Discount
      rate
    
    
    6.25
    %
    
    6.75
    %
    
    7.25
    %
    
    6.25
    %
    
    6.75
    %
    
    7.25
    %Expected
      long-term return on plan assets
    
    
    9.00
    %
    
    9.00
    %
    
    10.25
    %
    
    9.00
    %
    
    9.00
    %
    
    10.25
    %Rate of
      compensation increase
    
    
    3.50
    %
    
    3.50
    %
    
    4.00
    %








In selecting an
assumed discount rate, FirstEnergy considers currently available rates of return
on high-quality fixed income investments expected to be available during the
period to maturity of the pension and other postretirement benefit obligations.
The assumed rate of return on pension plan assets considers historical market
returns and economic forecasts for the types of investments held by the
Company's pension trusts. The long-term rate of return is developed considering
the portfolio’s asset allocation strategy.





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








**Assumed
      Health Care Cost Trend Rates****As of
      December 31**
    
    **2004**
    
    **2003**Health care
      cost trend rate assumed for nextyear
      (pre/post-Medicare)
    
    
    9%-11
    %
    
    10%-12
    %Rate to which
      the cost trend rate is assumed todecline (the
      ultimate trend rate)
    
    
    5
    %
    
    5
    %Year that the
      rate reaches the ultimate trendrate
      (pre/post-Medicare)
    
    
    2009-2011
    
    
    2009-2011








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








**1-Percentage-**
    
    **1-Percentage-****Point
      Increase**
    
    **Point
      Decrease*****(In
      millions)***Effect on
      total of service and interest
      cost
    
    $
    19
    
    $
    (16
    )Effect on
      postretirement benefit
      obligation
    
    $
    205
    
    $
    (179
    )











58





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.
T he
plan amendment, which increases cost sharing by employees and retirees effective
January 1, 2005, reduced postretirement benefit costs by $51 million during
2004.





Consistent with the
guidance in FSP 106-2 issued on 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. This reduction was accounted for as an actuarial gain
in 2004 pursuant to FSP 106-2. The subsidy reduced net periodic postretirement
benefit costs by $48 million during 2004.





As a result of its
voluntary contribution and the increased market value of pension plan assets,
FirstEnergy reduced its accrued benefit cost as of December 31, 2004 by
$424 million. As prescribed by SFAS 87, FirstEnergy reduced its additional
minimum liability by $15 million, recording a decrease in an intangible asset of
$9 million and crediting OCI by $6 million. The balance in AOCL of $296 million
(net of $208 million in deferred taxes) will reverse in future periods to the
extent the fair value of trust assets exceeds the accumulated benefit
obligation.





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








**Pension
      Benefits**
    
    **Other
      Benefits*****(In
      millions)***2005
    
    $
    228
    
    $
    1112006
    
    
    228
    
    
    1062007
    
    
    236
    
    
    1092008
    
    
    247
    
    
    1122009
    
    
    264
    
    
    115Years 2010 -
      2014
    
    
    1,531
    
    
    627








**4.**
    **STOCK-BASED
      COMPENSATION PLANS**





FirstEnergy has
four stock-based compensation programs: Long-term Incentive Program (LTIP);
Executive Deferred Compensation Plan (EDCP); Employee Stock Ownership Plan
(ESOP); and the Deferred Compensation Plan for Outside Directors (DCPD).
FirstEnergy has also assumed responsibility for several stock-based plans
through acquisitions.  In 2001,
FirstEnergy assumed responsibility for two stock-based plans as a result of its
acquisition of GPU. No further stock-based compensation can be awarded under
GPU’s Stock Option and Restricted Stock Plan for MYR Group Inc. Employees (MYR
Plan) or 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries (GPU Plan).
All options and restricted stock under both plans have been converted into
FirstEnergy options and restricted stock. Options under the GPU Plan became
fully vested on November 7, 2001, and will expire on or before June 1,
2010. Under the MYR Plan, all options and restricted stock maintained their
original vesting periods, which range from one to four years, and will expire on
or before December 17, 2006. The Centerior Equity Plan (CE Plan) is an
additional stock-based plan administered by FirstEnergy for which it assumed
responsibility as a result of the acquisition of Centerior Energy Corporation in
1997. All options are fully vested under the CE Plan, and no further awards are
permitted. Outstanding options will expire on or before February 25, 2007.





**(A)**
    **LTIP**





FirstEnergy’s LTIP
includes three stock-based compensation programs - restricted stock, stock
options, and performance shares.





Under FirstEnergy’s
LTIP, total awards cannot exceed 22.5 million shares of common stock or their
equivalent. Only stock options and restricted stock have currently been
designated to pay out in common stock, with vesting periods ranging from two
months to seven years. Performance share awards are currently designated to be
paid in cash rather than common stock and therefore do not count against the
limit on stock-based awards. As of December 31, 2004, 4.5 million shares
were available for future awards.





*Restricted
Stock*





Eligible employees
receive awards of FirstEnergy common stock subject to restrictions. Those
restrictions lapse over a defined period of time or based on performance.
Dividends are received on the restricted stock and are reinvested in additional
shares. Restricted common
stock grants under the FE Plan were as follows:





59








**2004**
    **2003***
    **2002**Restricted
      common shares granted
    62,370
    
    36,922Weighted
      average market price
    $40.69
    
    $36.04Weighted
      average vesting period
      (years)
    2.7
    
    3.2Dividends
      restricted
    Yes
    
    Yes





*  No restricted stock
was granted.








Compensation
expense recognized for restricted stock during 2004, 2003 and 2002 totaled
$1,982,000, $1,747,000 and $2,259,000, respectively.





*Stock
Options*





Stock option grants
are provided to eligible employees allowing them to purchase a specified number
of common shares at a fixed grant price over a defined period of time. Stock
option activities under the FE Programs for the past three years were as
follows:








**Number
      of**
    
    **Weighted
      Average****Stock
      Option Activities**
    
    **Options**
    
    **Exercise
      Price**Balance,
      January 1, 2002
    
    
    8,447,688
    
    $
    26.04(1,828,341
      options exercisable)
    
    
    
    
    
    24.83Options
      granted
    
    
    3,399,579
    
    
    34.48Options
      exercised
    
    
    1,018,852
    
    
    23.56Options
      forfeited
    
    
    392,929
    
    
    28.19Balance,
      December 31, 2002
    
    
    10,435,486
    
    
    28.95(1,400,206
      options exercisable)
    
    
    
    
    
    26.07Options
      granted
    
    
    3,981,100
    
    
    29.71Options
      exercised
    
    
    455,986
    
    
    25.94Options
      forfeited
    
    
    311,731
    
    
    29.09Balance,
      December 31, 2003
    
    
    13,648,869
    
    
    29.27(1,919,662
      options exercisable)
    
    
    
    
    
    29.67Options
      granted
    
    
    3,373,459
    
    
    38.77Options
      exercised
    
    
    3,622,148
    
    
    26.52Options
      forfeited
    
    
    167,425
    
    
    32.58Balance,
      December 31, 2004
    
    
    13,232,755
    
    
    32.40(3,175,023
      options exercisable)
    
    
    
    
    
    29.07








Options outstanding
by plan and range of exercise price as of December 31, 2004 were as
follows:





**Options
      Outstanding**
    
    **Options
      Exercisable****Range
      of**
    
    **Weighted**
      **Average**
    **Remaining**
    
    **Weighted**
      **Average****FE
      Program**
    **Exercise
      Prices**
    **Shares**
    **Exercise
      Price**
    **Contractual
      Life**
    **Shares**
    **Exercise
      Price****FE
      plan**
    $19.31 -
      $29.87
    6,972,940
    $28.82
    7.0
    1,903,790
    $26.72$30.17 -
      $39.46
    5,907,710
    $36.89
    8.3
    919,128
    $34.37**Plans
      acquired****Through
      merger:****GPU
      plan**
    $23.75 -
      $35.92
    341,455
    $28.35
    4.4
    341,455
    $28.35**MYR
      plan**
    $ 9.35 -
      $14.23
    8,550
    $12.70
    4.5
    8,550
    $12.70**CE
      plan**
    $25.14 -
      $25.15
    2,100
    $25.14
    2.2
    2,100
    $25.14**Total**
    
    13,232,755
    $32.40
    7.5
    3,175,023
    $29.07










60





The weighted
average fair value of options granted in 2004, 2003 and 2002, respectively, are
estimated below using the Black-Scholes option-pricing model and the following
assumptions:








**2004**
    
    **2003**
    
    **2002**Fair value
      per option
    
    $
    6.72
    
    $
    5.09
    
    $
    6.45Weighted
      average valuation assumptions:Expected
      option term (years)
    
    
    7.6
    
    
    7.9
    
    
    8.1Expected
      volatility
    
    
    26.25
    %
    
    26.91
    %
    
    23.31
    %Expected
      dividend yield
    
    
    3.88
    %
    
    5.09
    %
    
    4.36
    %Risk-free
      interest rate
    
    
    1.99
    %
    
    3.67
    %
    
    4.60
    %





Compensation
expense for FirstEnergy stock options is based on intrinsic value, which equals
any positive difference between FirstEnergy's common stock price on the option's
grant date and the option's exercise price. The exercise prices of all stock
options granted in 2004, 2003 and 2002 equaled the market price of FirstEnergy's
common stock on the options' grant dates. If fair value accounting were applied
to FirstEnergy's stock options, net income and earnings per share would be
reduced as summarized below.








**2004**
    
    **2003**
    
    **2002*****(In
      thousands, except per share amounts)***Net Income,
      as reported
    
    $
    878,175
    
    $
    422,764
    
    $
    552,804Add back
      compensation expensereported in
      net income, net of tax(based on APB
      25)*
    
    
    21,177
    
    
    23,625
    
    
    22,981Deduct
      compensation expense basedupon
      estimated fair value, net of tax*
    
    
    (35,660
    )
    
    (35,816
    )
    
    (31,640
    )Pro forma net
      income
    
    $
    863,692
    
    $
    410,573
    
    $
    544,145Earnings Per
      Share of Common Stock -BasicAs
      Reported
    
    $
    2.68
    
    $
    1.39
    
    $
    1.89Pro
      Forma
    
    $
    2.64
    
    $
    1.35
    
    $
    1.86DilutedAs
      Reported
    
    $
    2.67
    
    $
    1.39
    
    $
    1.88Pro
      Forma
    
    $
    2.63
    
    $
    1.35
    
    $
    1.85





*
Includes restricted stock, stock options, performance shares, ESOP, EDCP and
DCPD.





FirstEnergy
anticipates reducing its use of stock options beginning in 2005 and increasing
its use of performance-based, restricted stock units. Therefore, the pro forma
effects of applying SFAS 123 may not be representative of its future effect.
FirstEnergy has not and does not expect to accelerate out-of-the-money options
in anticipation of implementing revisions to SFAS 123 on July 1, 2005 (see Note
15 - "New Accounting Standards and Interpretations").


*Performance
Shares*





Performance shares
are share equivalents and do not have voting rights. The shares track the
performance of FirstEnergy's common stock over a three-year vesting period.
During that time dividend equivalents are converted into additional shares. The
final account value may be adjusted based on the ranking of FirstEnergy stock to
a composite of peer companies. Compensation expense recognized for performance
shares during 2004, 2003 and 2002 totaled $4,924,000, $7,131,000 and $6,757,000,
respectively.





**(B)**
    **ESOP**





An ESOP Trust funds
most of the matching contribution for FirstEnergy's 401(k) savings plan. All
full-time employees eligible for participation in the 401(k) savings plan are
covered by the ESOP. The ESOP borrowed $200 million from OE and acquired
10,654,114 shares of OE's common stock (subsequently converted to FirstEnergy
common stock) through market purchases. Dividends on ESOP shares are used to
service the debt. Shares are released from the ESOP on a pro rata basis as debt
service payments are made. In 2004, 2003 and 2002, 864,151 shares, 1,069,318
shares and 1,151,106 shares, respectively, were allocated to employees with the
corresponding expense recognized based on the shares allocated method. The fair
value of 2,032,800 shares unallocated, as of December 31, 2004, was
approximately $80 million. Total ESOP-related compensation expense was
calculated as follows:








61








**2004**
    
    **2003**
    
    **2002*****(In
      millions)***Base
      compensation
    
    $
    32
    
    $
    35
    
    $
    34Dividends on
      common stock held by the
      ESOP and used to
      service debt
    
    
    (9
    )
    
    (9
    )
    
    (8
    )Net
      expense
    
    $
    23
    
    $
    26
    
    $
    26








**(C)**
    **EDCP**





Under the EDCP,
covered employees can direct a portion of their compensation, including annual
incentive awards and/or long-term incentive awards, into an unfunded FirstEnergy
stock account to receive vested stock units. An additional 20 percent premium is
received in the form of stock units based on the amount allocated to the
FirstEnergy stock account. Dividends are calculated quarterly on stock units
outstanding and are paid in the form of additional stock units. Upon withdrawal,
stock units are converted to FirstEnergy shares. Payout typically occurs three
years from the date of deferral; however, an election can be made in the year
prior to payout to further defer shares into a retirement stock account that
will pay out in cash upon retirement. Of the 1.3 million EDCP stock units
authorized, 776,072 stock units were available for future award as of December
31, 2004. Compensation expense recognized on EDCP stock units in 2004, 2003 and
2002 totaled $2,311,000, $2,312,000 and $206,000, respectively.





**(D)**
    **DCPD**





Under the DCPD,
directors can elect to allocate all or a portion of their cash retainers,
meeting fees and chair fees to deferred stock or deferred cash accounts. If the
funds are deferred into the stock account, a 20 percent match is added to the
funds allocated. The 20 percent match and any appreciation on it are forfeited
if the director leaves the Board within three years from the date of deferral
for any reason other than retirement, disability, death, upon a change in
control, or when a director is ineligible to stand for re-election. Compensation
expense is recognized for the 20 percent match over the three-year vesting
period. Directors may also elect to defer their equity retainers into the
deferred stock account, however, they do not receive a 20 percent match for this
deferral. DCPD expenses recognized in 2004, 2003 and 2002 were $3,556,000
$2,233,000 and $2,728,000, respectively.





**5.**
    **FAIR
      VALUE OF FINANCIAL INSTRUMENTS**





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





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




**2004**
    
    **2003****Carrying**
    
    **Fair**
    
    **Carrying**
    
    **Fair****Value**
    
    **Value**
    
    **Value**
    
    **Value*****(In
      millions)***Long-term
      debt
    
    $
    10,787
    
    $
    11,341
    
    $
    11,177
    
    $
    11,648Subordinated
      debentures to affiliated
      trusts
    
    
    103
    
    
    112
    
    
    294
    
    
    322Preferred
      stock subject to
      mandatory
      redemption
    
    
    17
    
    
    16
    
    
    19
    
    
    19$
    10,907
    
    $
    11,469
    
    $
    11,490
    
    $
    11,989


The fair values of
long-term debt and other long-term obligations reflect the present value of the
cash outflows relating to those securities based on the current call price, the
yield to maturity or the yield to call, as deemed appropriate at the end of each
respective year. The yields assumed were based on securities with similar
characteristics offered by corporations with credit ratings similar to the
Companies' ratings.





**Investments**





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





62








**2004**
    
    **2003****Carrying**
    
    **Fair**
    
    **Carrying**
    
    **Fair****Value**
    
    **Value**
    
    **Value**
    
    **Value*****(In
      millions)***Debt
      securities:(1)-Government
      obligations
    
    $
    797
    
    $
    797
    
    $
    707
    
    $
    707-Corporate
      debt securities(2)
    
    
    1,205
    
    
    1,362
    
    
    1,492
    
    
    1,601-Mortgage-backed
      securities
    
    
    2
    
    
    2
    
    
    --
    
    
    --2,004
    
    
    2,161
    
    
    2,199
    
    
    2,308Equity
      securities(1)
    
    
    1,033
    
    
    1,033
    
    
    1,068
    
    
    1,068$
    3,037
    
    $
    3,194
    
    $
    3,267
    
    $
    3,376





(1)
    Includes
      nuclear decommissioning, nuclear fuel disposal and NUG trust
      investments.


(2)
    Includes
      investments in lease obligation bonds (See Note
6).








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





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








**2004**
    
    **2003****Cost**
    
    **Unrealized**
    
    **Unrealized**
    
    **Fair**
    
    **Cost**
    
    **Unrealized**
    
    **Unrealized**
    
    **Fair****Basis**
    
    **Gains**
    
    **Losses**
    
    **Value**
    
    **Basis**
    
    **Gains**
    
    **Losses**
    
    **Value*****(In
      millions)***Debt
      securities
    
    $
    616
    
    $
    19
    
    $
    3
    
    $
    632
    
    $
    548
    
    $
    26
    
    $
    1
    
    $
    573Equity
      securities
    
    
    763
    
    
    207
    
    
    19
    
    
    951
    
    
    593
    
    
    217
    
    
    31
    
    
    779$
    1,379
    
    $
    226
    
    $
    22
    
    $
    1,583
    
    $
    1,141
    
    $
    243
    
    $
    32
    
    $
    1,352





Proceeds from the
sale of decommissioning trust investments, realized gains and losses on those
sales, and interest and dividend income for the three years ended
December 31, 2004 were as follows:








**2004**
    
    **2003**
    
    **2002*****(In
      millions)***Proceeds from
      sales
    
    $
    1,234
    
    $
    758
    
    $
    599Realized
      gains
    
    
    144
    
    
    38
    
    
    32Realized
      losses
    
    
    43
    
    
    32
    
    
    47Interest and
      dividend income
    
    
    45
    
    
    37
    
    
    33








The following table
provides the fair value of and unrealized losses on nuclear decommissioning
trust investments that are deemed to be temporarily impaired as of
December 31, 2004:


**Less
      Than 12 Months**
    
    **12
      Months or More**
    
    **Total****Fair**
    
    **Unrealized**
    
    **Fair**
    
    **Unrealized**
    
    **Fair**
    
    **Unrealized****Value**
    
    **Losses**
    
    **Value**
    
    **Losses**
    
    **Value**
    
    **Losses*****(In
      millions)***Debt
      securities
    
    $
    175
    
    $
    3
    
    $
    20
    
    $
    --
    
    $
    195
    
    $
    3Equity
      securities
    
    
    129
    
    
    12
    
    
    39
    
    
    7
    
    
    168
    
    
    19$
    304
    
    $
    15
    
    $
    59
    
    $
    7
    
    $
    363
    
    $
    22





The Companies
periodically evaluate the securities held by their nuclear decommissioning
trusts for other-than-temporary impairment. FirstEnergy considers the length of
time and the extent to which the security's fair value has been less than its
cost basis and other factors to determine whether impairment is other than
temporary. Unrealized gains and losses applicable to the decommissioning trusts
of FirstEnergy's Ohio Companies are recognized in OCI in accordance with SFAS
115, as fluctuations in fair value will eventually affect earnings. The
decommissioning trusts of FirstEnergy's Pennsylvania and New Jersey Companies
are subject to regulatory accounting in accordance with SFAS 71. Net
unrealized gains and losses are recorded as regulatory liabilities or assets
since the difference between investments held in trust and the decommissioning
liabilities are recovered from or refunded to customers.





63


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




**Derivatives**





FirstEnergy is
exposed to financial risks resulting from the fluctuation of interest rates and
commodity prices, including prices for 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 members of senior management, provides general
management oversight to risk management activities throughout the Company. They
are responsible for promoting the effective design and implementation of sound
risk management programs. They also oversee compliance with corporate risk
management policies and established risk management practices.





How derivative
instruments are used and classified determines how they are reported in
FirstEnergy's financial statements. FirstEnergy accounts for derivative
instruments on its Consolidated Balance Sheet at their fair value unless they
meet the normal purchase and normal sales criteria. The changes in the fair
value of a derivative instrument are recorded in current earnings, in other
comprehensive income, or as part of the value of the hedged item depending on
whether or not it is designated as part of a hedge transaction and on the nature
of the hedge transaction. FirstEnergy's primary ongoing hedging activity
involves cash flow hedges of electricity and natural gas purchases. The maximum
periods over which the variability of electricity and natural gas cash flows are
hedged are two and three years, respectively. Gains and losses from hedges of
commodity price risks are included in net income when the underlying hedged
commodities are delivered. Also, gains and losses are included in net income
when ineffectiveness occurs on certain natural gas hedges. The impact of
ineffectiveness on earnings during 2004 was not material. FirstEnergy entered
into interest rate derivative transactions during 2001 to hedge a portion of the
anticipated interest payments on debt related to the GPU acquisition. Gains and
losses from hedges of anticipated interest payments on acquisition debt are
included in net income over the periods that hedged interest payments are made -
5, 10 and 30 years. Gains and losses from derivative contracts are included in
other operating expenses. AOCL as of December 31, 2004 includes a net
deferred loss of $92 million for derivative hedging activity. The $19 million
decrease from the December 31, 2003 balance of $111 million includes a $11
million reduction due to the sale of GLEP, $3 million reduction related to
current hedging activity and a $5 million decrease due to net hedge losses
included in earnings during the year. Approximately $14 million (after tax) of
the current net deferred loss on derivative instruments in AOCL is expected to
be reclassified to earnings during the next twelve months as hedged transactions
occur. The fair value of these derivative instruments will continue to fluctuate
from period to period based on various market factors.





During 2004,
FirstEnergy executed fixed-for-floating interest rate swap agreements, whereby
FirstEnergy receives fixed cash flows based on the fixed coupons of the hedged
securities and pays variable cash flows based on short-term variable market
interest rates (3 and 6 months LIBOR index). 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, fixed interest rates received, and interest
payment dates match those of the underlying obligations. FirstEnergy entered
into interest rate swap agreements on a $900 million notional amount of
subsidiaries’ senior notes and subordinated debentures with a weighted average
fixed interest rate of 5.67%. In addition, FirstEnergy unwound swaps with a
total notional amount of $400 million from which it received $12 million in cash
gains during 2004. The gains will be recognized over the remaining maturity of
each respective hedged security as reduced interest expense. As of
December 31, 2004, the aggregate notional value of interest rate swap
agreements outstanding was $1.65 billion.





FirstEnergy engages
in the trading of commodity derivatives and periodically experiences net open
positions. FirstEnergy's risk management policies limit the exposure to market
risk from open positions and require daily reporting to management of potential
financial exposures. Discretionary trading in 2004 resulted in a $2 million
gain.





**6.**
    **LEASES**





The Companies lease
certain generating facilities, office space and other property and equipment
under cancelable and noncancelable leases.





OE sold portions of
its ownership interests in Perry Unit 1 and Beaver Valley Unit 2 and entered
into operating leases on the portions sold for basic lease terms of
approximately 29 years. CEI and TE also sold portions of their ownership
interests in Beaver Valley Unit 2 and Bruce Mansfield Units 1, 2 and 3 and
entered into similar operating leases for lease terms of approximately 30 years.
During the terms of their respective leases, OE, CEI and TE continue to be
responsible, to the extent of their individual combined ownership and leasehold
interests, for costs associated with the units including construction
expenditures, operation and maintenance expenses, insurance, nuclear fuel,
property taxes and decommissioning. They have the right, at the expiration of
the respective basic lease terms, to renew their respective leases. They also
have the right to purchase the facilities at the expiration of the basic lease
term or any renewal term at a price equal to the fair market value of the
facilities. The basic rental payments are adjusted when applicable federal tax
law changes.





64


Consistent with the
regulatory treatment, the rentals for capital and operating leases are charged
to operating expenses on the Consolidated Statements of Income. Such costs for
the three years ended December 31, 2004 are summarized as
follows:





**2004**
    
    **2003**
    
    **2002*****(In
      millions)***Operating
      leasesInterest
      element
    
    $
    172
    
    $
    181
    
    $
    188Other
    
    
    126
    
    
    150
    
    
    136Capital
      leasesInterest
      element
    
    
    1
    
    
    2
    
    
    2Other
    
    
    3
    
    
    2
    
    
    3Total
      rentals
    
    $
    302
    
    $
    335
    
    $
    329





OE invested in the
PNBV Capital Trust, which was established to purchase a portion of the lease
obligation bonds issued on behalf of lessors in OE's Perry Unit 1 and Beaver
Valley Unit 2 sale and leaseback transactions. CEI and TE established the
Shippingport Capital Trust to purchase the lease obligation bonds issued on
behalf of lessors in their Bruce Mansfield Units 1, 2 and 3 sale and leaseback
transactions. The PNBV and Shippingport Capital Trust arrangements effectively
reduce lease costs related to those transactions (see Note 7).





The future minimum
lease payments as of December 31, 2004 are:








**Operating
      Leases****Capital**
    
    **Lease**
    
    **Capital****Leases**
    
    **Payments**
    
    **Trusts**
    
    **Net*****(In
      millions)***2005
    
    $
    5
    
    $
    313
    
    $
    130
    
    $
    1832006
    
    
    5
    
    
    322
    
    
    142
    
    
    1802007
    
    
    1
    
    
    299
    
    
    130
    
    
    1692008
    
    
    1
    
    
    294
    
    
    105
    
    
    1892009
    
    
    1
    
    
    298
    
    
    111
    
    
    187Years
      thereafter
    
    
    6
    
    
    2,217
    
    
    763
    
    
    1,454Total minimum
      lease payments
    
    
    19
    
    $
    3,743
    
    $
    1,381
    
    $
    2,362Executory
      costs
    
    
    4Net minimum
      lease payments
    
    
    15Interest
      portion
    
    
    4Present value
      of net minimumlease
      payments
    
    
    11Less current
      portion
    
    
    2Noncurrent
      portion
    
    $
    9







FirstEnergy has
recorded above-market lease liabilities for Beaver Valley Unit 2 and the Bruce
Mansfield Plant associated with the 1997 merger between OE and Centerior. The
total above-market lease obligation of $722 million associated with Beaver
Valley Unit 2 is being amortized on a straight-line basis through the end of the
lease term in 2017 (approximately $37 million per year). The total above-market
lease obligation of $755 million associated with the Bruce Mansfield Plant is
being amortized on a straight-line basis through the end of 2016 (approximately
$48 million per year). As of December 31, 2004 the above-market lease
liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant totaled $1.0
billion, of which $85 million is current.





**7.**
    **VARIABLE
      INTEREST ENTITIES**





FIN 46R addresses
the consolidation of VIEs, including special-purpose entities, that are not
controlled through voting interests or in which the equity investors do not bear
the residual economic risks and rewards. FirstEnergy adopted FIN 46R for
special-purpose entities as of December 31, 2003 and for all other entities in
the first quarter of 2004. The 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.





65





**Leases**


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 the sale and leaseback transactions discussed above in Note
6. 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. 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.





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 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.





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 $673
million, $115 million and $570 million, respectively, that would not be payable
if the casualty value payments are made.





**Power
Purchase Agreements**


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 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
nor 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 requests, on a quarterly basis, 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 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 cost of
power purchased from these entities during 2004, 2003 and 2002 was $210 million,
$194 million and $184 million, respectively.





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.





**8.**
    **DIVESTITURES**





**International
Operations**





FirstEnergy
completed the sale of its international operations in January 2004 with the
sales of its remaining 20.1 percent interest in Avon (parent of Midlands
Electricity in the United Kingdom) on January 16, 2004, and its
28.67 percent interest in TEBSA for $12 million on January 30, 2004. Impairment charges
related to TEBSA and Avon (included in Other Operating Expenses on the
Consolidated Statements of Income) 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.





66


International
operations in Bolivia were divested by the December 2003 sale of FirstEnergy's
wholly owned subsidiary, Guaracachi America, Inc., a holding company with a
50.001 percent interest in EGSA, resulting in a loss on sale of $33 million
(recognized in Discontinued Operations in the Consolidated Statement of Income
for the year ended December 31, 2003). International operations in Argentina
represented by FirstEnergy's ownership in Emdersa were divested through the
abandonment of its shares in Emdersa's parent company, GPU Argentina Holdings,
Inc. in April 2003. As a result of the abandonment, FirstEnergy recognized
a one-time, non-cash charge of $67 million, or $0.23 per share of common stock
in the second quarter of 2003. The charge did not include the expected income
tax benefits related to the abandonment, which were fully reserved during the
second quarter of 2003. FirstEnergy expects tax benefits of approximately $129
million, of which $50 million would increase net income in the period that it
becomes probable those benefits will be realized. The remaining $79 million of
tax benefits would reduce goodwill recognized in connection with the acquisition
of GPU.





FirstEnergy had
sold a 79.9 percent equity interest in Avon in May 2002 to Aquila, Inc. for
approximately $1.9 billion (consisting of the assumption of $1.7 billion of
debt, $155 million in cash and a $87 million note receivable). In the fourth
quarter of 2002, FirstEnergy recorded a $50 million after-tax charge to reduce
the carrying value of its remaining 20.1 percent interest. After reaching
agreement to sell its remaining 20.1 percent interest in the fourth quarter of
2003, FirstEnergy recorded a $5 million after-tax charge to reduce the carrying
value. These charges were included in Other Operating Expenses on the
Consolidated Statements of Income for the years ended December 31, 2002 and
2003, respectively. In the second quarter of 2003, FirstEnergy recognized an
impairment of $13 million ($8 million net of tax) related to the carrying value
of the note receivable from Aquila. After receiving the first annual installment
payment of $19 million in May 2003, FirstEnergy sold the remaining balance
of its note receivable in the secondary market and received $63 million in
proceeds in July 2003.





**Generation
Assets**





In August 2002,
FirstEnergy cancelled a November 2001 agreement to sell four coal-fired power
plants (2,535 MW) to NRG Energy Inc. because NRG stated that it could not
complete the transaction under the original terms of the agreement. NRG filed
voluntary bankruptcy petitions in May 2003; subsequently, FirstEnergy reached an
agreement for settlement of its claim against NRG. FirstEnergy sold its entire
claim (including $32 million of cash proceeds received in December 2003) for
$170 million in January 2004.





**Other
Domestic Operations**





FirstEnergy sold
its 50 percent 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. In 2003,
FirstEnergy sold three FSG subsidiaries - Ancoma, Inc., a mechanical contracting
company based in Rochester, New York, and Virginia-based Colonial Mechanical and
Webb Technologies - and a MARBEL subsidiary - Northeast Ohio Natural Gas (see
Note 2(J)).





**9.**
    **REGULATORY
      MATTERS**





**Reliability
Initiatives**


In late 2003 and
early 2004, a series of letters, reports and recommendations were issued from
various entities, including governmental, industry and ad hoc reliability
entities (PUCO, FERC, NERC and the U.S. - Canada Power System Outage Task Force)
regarding enhancements to regional reliability. With respect to each of these
reliability enhancement initiatives, FirstEnergy submitted its response to the
respective entity according to any required response dates. In 2004, FirstEnergy
completed implementation of all actions and initiatives related to enhancing
area reliability, improving voltage and reactive management, operator readiness
and training, and emergency response preparedness recommended for completion in
2004. Furthermore, FirstEnergy certified to NERC on June 30, 2004, with
minor exceptions noted, that FirstEnergy had completed the recommended
enhancements, policies, procedures and actions it had recommended be completed
by June 30, 2004. In addition, FirstEnergy requested, and NERC provided, a
technical assistance team of experts to assist in implementing and confirming
timely and successful completion of various initiatives. The NERC-assembled
independent verification team confirmed on July 14, 2004, that FirstEnergy
had implemented the NERC Recommended Actions to Prevent and Mitigate the Impacts
of Future Cascading Blackouts required to be completed by June 30, 2004, as
well as NERC recommendations contained in the Control Area Readiness Audit
Report required to be completed by summer 2004, and recommendations in the
U.S. -
Canada Power System Outage Task Force Report directed toward FirstEnergy and
required to be completed by June 30, 2004, with minor exceptions noted by
FirstEnergy. On December 28, 2004, FirstEnergy submitted a follow-up to its
June 30, 2004 Certification and Report of Completion to NERC addressing the
minor exceptions, which are now essentially complete.





67


FirstEnergy is
proceeding with the implementation of the recommendations that were to be
completed subsequent to 2004 and will continue to periodically assess the
FERC-ordered Reliability Study recommendations for forecasted 2009 system
conditions, recognizing revised load forecasts and other changing system
conditions which may impact the recommendations. Thus far, implementation of the
recommendations has not required, nor is expected to require, substantial
investment in new, or material upgrades, to existing equipment. 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. Finally, the PUCO is continuing to
review the FirstEnergy filing that addressed upgrades to control room computer
hardware and software and enhancements to the training of control room
operators, before determining the next steps, if any, in the proceeding.




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. On July 16, 2003,
the NJBPU initiated an investigation into the cause of JCP&L's outages of
the July 4, 2003 weekend. The NJBPU selected an SRM to oversee and make
recommendations on appropriate courses of action necessary to ensure system-wide
reliability. Additionally, pursuant to the stipulation of settlement that was
adopted in the NJBPU's Order of March 13, 2003 in its docket relating to
the investigation of outages in August 2002, the NJBPU, through an independent
auditor working under direction of the NJBPU Staff, undertook a review and
focused audit of JCP&L's Planning and Operations and Maintenance programs
and practices (Focused Audit). Subsequent to the initial engagement of the
auditor, the scope of the review was expanded to include the outages during July
2003.





Both the
independent auditor and the SRM submitted interim reports primarily addressing
improvements to be made prior to the next occurrence of peak loads in the summer
of 2004. On December 17, 2003, the NJBPU adopted the SRM's interim
recommendations related to service reliability. With the assistance of the
independent auditor and the SRM, JCP&L and the NJBPU staff created a
Memorandum of Understanding (MOU) that set out specific tasks to be performed by
JCP&L and a timetable for completion. On March 29, 2004, the NJBPU
adopted the MOU and endorsed JCP&L's ongoing actions to implement the MOU.
On June 9, 2004, the NJBPU approved a Stipulation that incorporates the
final report of the SRM and the Executive Summary and Recommendation portions of
the final report of the Focused Audit. A Final Order in the Focused Audit docket
was issued by the NJBPU on July 23, 2004. JCP&L continues to file
compliance reports reflecting activities associated with the MOU and
Stipulation.





In May 2004, the
PPUC issued an order approving the revised reliability benchmark and standards,
including revised benchmarks and standards for Met-Ed, Penelec and Penn. 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.
Evidentiary hearings have been scheduled for September 2005. 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, ongoing periodic
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. The settlement also outlines an
expedited remediation process to address any alleged non-compliance with terms
of the settlement and an expedited PPUC hearing process if remediation is
unsuccessful. O n November 4,
2004, the PPUC accepted the recommendation of the ALJ approving the
settlement.





**Ohio**





In October 2003,
the Ohio Companies filed an application for a Rate Stabilization Plan with the
PUCO to establish generation service rates beginning January 1, 2006, in
response to PUCO concerns about price and supply uncertainty following the end
of the Ohio Companies' transition plan market development period. On
February 24, 2004, the Ohio Companies filed a revised Rate Stabilization
Plan to address PUCO concerns related to the original 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
August 5, 2004, the Ohio Companies accepted the Rate Stabilization Plan as
modified and approved by the PUCO on August 4, 2004. In the second quarter
of 2004, the Ohio Companies implemented the accounting modifications related to
the extended amortization periods and interest costs deferral on the deferred
customer shopping incentive balances. On October 1 and October 4,
2004, the OCC and NOAC, respectively, filed appeals with the Supreme Court of
Ohio to overturn the June 9, 2004 PUCO order and associated entries on
rehearing.





The revised Rate
Stabilization Plan extends current generation prices through 2008, ensuring
adequate generation supply at stabilized prices, and continues the Ohio
Companies' support of energy efficiency and economic development efforts. Other
key components of the revised Rate Stabilization Plan include the
following:





68








·
    extension of
      the transition cost amortization period for OE from 2006 to as late as
      2007; for CEI from 2008 to as
      late as
      mid-2009 and for TE from mid-2007 to as late as
  mid-2008;·
    deferral of
      interest costs on the accumulated customer shopping incentives as new
      regulatory assets; and·
    ability to
      request increases in generation charges during 2006 through 2008, under
      certain limited conditions,
      for increases
      in fuel costs and taxes.








On December 9,
2004, the PUCO rejected the auction price results from a required competitive
bid process and issued an entry stating that the pricing under the approved
revised Rate Stabilization Plan will take effect on January 1, 2006. The
PUCO may cause the Ohio Companies to undertake, no more often than annually, a
similar competitive bid process to secure generation for the years 2007 and
2008. Any acceptance of future competitive bid results would terminate the Rate
Stabilization Plan pricing, but not the related approved accounting, and not
until twelve months after the PUCO authorizes such termination.





**New
Jersey**





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
December 31, 2004, the accumulated deferred cost balance totaled
approximately $446 million. New Jersey law allows for securitization of
JCP&L's deferred balance upon application by JCP&L and a determination
by the NJBPU that the conditions of the New Jersey restructuring legislation are
met. On February 14, 2003, JCP&L filed for approval of the
securitization of the deferred balance. There can be no assurance as to the
extent, if any, that the NJBPU will permit such securitization.





In July 2003,
the NJBPU announced its JCP&L base electric rate proceeding decision, which
reduced JCP&L's annual revenues effective August 1, 2003 and disallowed
$153 million of deferred energy costs. The NJBPU decision also provided for an
interim return on equity of 9.5% on JCP&L's rate base. The decision ordered
a Phase II proceeding be conducted to review whether JCP&L is in
compliance with current service reliability and quality standards. The BPU also
ordered that any expenditures and projects undertaken by JCP&L to increase
its system's reliability be reviewed as part of the Phase II proceeding, to
determine their prudence and reasonableness for rate recovery. 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.
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. 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. JCP&L filed an August 15, 2003 interim motion for rehearing
and reconsideration with the NJBPU and a June 1, 2004 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 costs. Management is unable to predict when a
decision may be reached by the NJBPU.





On July 16,
2004, JCP&L filed the Phase II petition and testimony with the NJBPU,
requesting an increase in base rates of $36 million for 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. The Ratepayer Advocate filed testimony on November 16, 2004, and
JCP&L submitted rebuttal testimony on January 4, 2005. Settlement
conferences are ongoing.


JCP&L sells all
self-supplied energy (NUGs and owned generation) to the wholesale market with
offsetting credits to its deferred energy balance with the exception of 300 MW
from JCP&L's 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. The NJBPU
decision on the BGS post transition year three process 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 for the supply period beginning June 1, 2005
was completed in February 2005.





69


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 customers without a reduction,
termination or capping of the funding. On September 30, 2004, JCP&L
filed an updated TMI-2 decommissioning study (see Note 11 - 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. The
Ratepayer Advocate filed comments on February 28, 2005. A schedule for further
proceedings has not yet been set.




**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 Met-Ed and Penelec PLR deferred accounting treatment for
energy costs. A February 2002 Commonwealth Court of Pennsylvania decision
affirmed the PPUC decision regarding approval of the merger, remanded the issues
of quantification and allocation of merger savings to the PPUC and denied the
PLR deferral accounting treatment. In October 2003, the PPUC issued an order
concluding that the Commonwealth Court reversed the PPUC’s June 2001 order
in its entirety. In accordance with the PPUC's direction, Met-Ed and Penelec
filed supplements to their tariffs which were effective October 2003 that
reflected the CTC rates and shopping credits in effect prior to the
June 21, 2001 order.





In response to its
October 8, 2003 petition, the PPUC approved June 30, 2004 as the date for
Met-Ed's and Penelec's NUG trust fund refunds and denied their accounting
request regarding the CTC rate/shopping credit swap by requiring Met-Ed and
Penelec to treat the stipulated CTC rates that were in effect from
January 1, 2002 on a retroactive basis. Met-Ed and Penelec subsequently
filed with the Commonwealth Court, on October 31, 2003, an Application for
Clarification with the judge, 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. The Reargument Brief before the
Commonwealth Court was filed January 28, 2005.





In accordance with
PPUC directives, Met-Ed and Penelec have been negotiating with interested
parties in an attempt to resolve the merger savings issues that are the subject
of remand from the Commonwealth Court. These companies' combined portion of
total merger savings is estimated to be approximately $31.5 million. If no
settlement can be reached, Met-Ed and Penelec will take the position that any
portion of such savings should be allocated to customers during each company's
next rate proceeding.


Met-Ed and Penelec
purchase a portion of their PLR requirements from FES through a wholesale power
sales 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. Met-Ed and Penelec
are authorized to continue deferring differences between NUG contract costs and
current market prices.





**Transmission**





On November 1,
2004, ATSI requested authority from the FERC to defer approximately $54 million
of vegetation management costs ($13 deferred as of December 31, 2004
pending authorization) estimated to be incurred from 2004 through 2007. The FERC
approved ATSI's request to defer those costs on March 4, 2005.





ATSI and MISO filed
with the FERC on December 2, 2004, seeking approval for ATSI to have
transmission rates established based on a FERC-approved cost of service -
formula rate included in Attachment O under the MISO tariff. The ATSI Network
Service net revenue requirement increased under the formula rate to
approximately $159 million. On January 28, 2005, the FERC accepted for
filing the revised tariff sheets to become effective February 1, 2005,
subject to refund, and ordered a public hearing be held to address the
reasonableness of the proposal to eliminate the voltage-differentiated rate
design for the ATSI zone.





On
December 30, 2004, the Ohio Companies filed an application with the PUCO
seeking tariff adjustments to recover increases of approximately $30 million in
transmission and ancillary service costs beginning January 1, 2006. The
Ohio Companies also filed an application for authority to defer costs associated
with MISO Day 1, MISO Day 2, congestion fees, FERC assessment fees, and the ATSI
rate increase, as applicable, from October 1, 2003 through
December 31, 2005.





On January 12,
2005, Met-Ed and Penelec filed, before the PPUC, a request for deferral of
transmission-related costs beginning January 1, 2005, estimated to be
approximately $8 million per month.





Various parties
have intervened in each of the cases above.





70





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 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.





**10.**
    **CAPITALIZATION**





**(A)**
    **COMMON
      STOCK**





*Retained
Earnings and Dividends*





Under applicable
federal law, FirstEnergy (as a registered holding company) and its subsidiaries
can pay dividends only from retained, undistributed or current earnings, unless
the SEC specifically authorizes payment from other capital accounts. As of
December 31, 2004, FirstEnergy's unrestricted retained earnings were $1.9
billion. Provisions within the articles of incorporation, indentures and various
other agreements relating to the long-term debt and preferred stock of certain
FirstEnergy subsidiaries contain provisions that could restrict the payment of
dividends on their common and preferred stock. As of December 31, 2004,
there were no material restrictions on retained earnings under these agreements
for payment of cash dividends on FirstEnergy’s common stock.





On
November 30, 2004, the Board of Directors increased the indicated annual
dividend to $1.65 per share, payable quarterly at a rate of $0.4125 per share,
and declared the first quarter 2005 dividend. At December 31, 2004, accrued
dividends of approximately $135 million were included in other current
liabilities on the Consolidated Balance Sheet. Dividends declared in 2004 were
$1.9125 which included quarterly dividends of $0.375 per share paid in each
quarter of 2004 and a dividend of $0.4125 payable in the first quarter of 2005.
Dividends declared in 2003 were $1.50, which included quarterly dividends of
$0.375 per share paid in each quarter of 2003. The amount and timing of all
dividend declarations are subject to the discretion of the Board and its
consideration of business conditions, results of operations, financial
conditions and other factors.





**(B)**
    **PREFERRED
      AND PREFERENCE STOCK**





All preferred stock
may be redeemed by the Companies in whole, or in part, with 30-90 days' notice.





CEI will exercise
its option to redeem all outstanding shares of two series of preferred stock
during the first quarter of 2005 as follows:





**Series**
    **Outstanding
      Shares**
    **Call
      Price**7.40A
    500,000
    101.00L
    474,000
    100.00








Met-Ed's and
Penelec's preferred stock authorizations consist of 10 million and 11.435
million shares, respectively, without par value. No preferred shares are
currently outstanding for those companies.





The Companies'
preference stock authorization consists of 8 million shares without par value
for OE; 3 million shares without par value for CEI; and 5 million shares, $25
par value for TE. No preference shares are currently outstanding.





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





*Preferred Stock
Subject to Mandatory Redemption*





SFAS 150 requires
financial instruments issued in the form of shares that are mandatorily
redeemable to be classified as long-term debt. Annual sinking fund provisions
for the Companies' preferred stock are as follows:





**Redemption****Price
      Per****Series**
    
    **Shares**
    
    **Share**CEI
    
    $
    7.35C
    
    
    10,000
    
    $
    100Penn
    
    
    7.625
    %
    
    7,500
    
    
    100





Annual sinking fund
requirements will be satisfied by the end of 2008 and consist of $1.8 million in
2005 and 2006, $12.3 million in 2007 and $1.0 million in 2008.





71





*Subordinated
Debentures to Affiliated Trusts*





As of
December 31, 2004, CEI's wholly owned statutory business trust, Cleveland
Electric Financing Trust, had $100 million of outstanding 9.00% preferred
securities maturing in 2031. The sole assets of the trust are CEI's subordinated
debentures with the same rate and maturity date as the preferred
securities.





CEI formed the
trust to sell preferred securities and invest the gross proceeds in the 9.00%
subordinated debentures of CEI. The sole assets of the trust are the applicable
subordinated debentures. Interest payment provisions of the subordinated
debentures match the distribution payment provisions of the trust's preferred
securities. In addition, upon redemption or payment at maturity of subordinated
debentures, the trust's preferred securities will be redeemed on a pro rata
basis at their liquidation value. Under certain circumstances, the applicable
subordinated debentures could be distributed to the holders of the outstanding
preferred securities of the trust in the event that the trust is liquidated. CEI
has effectively provided a full and unconditional guarantee of payments due on
the trust's preferred securities. The trust's preferred securities are
redeemable at 100 percent of their principal amount at CEI's option beginning in
December 2006. Interest on the subordinated debentures (and therefore
distributions on the trust's preferred securities) may be deferred for up to 60
months, but CEI may not pay dividends on, or redeem or acquire, any of its
cumulative preferred or common stock until deferred payments on its subordinated
debentures are paid in full.





Met-Ed and Penelec
had each formed statutory business trusts for substantially similar transactions
to those of CEI, with ownership of the respective Met-Ed and Penelec trusts
through separate wholly owned limited partnerships. In June 2004 and September
2004, respectively, Met-Ed and Penelec extinguished the subordinated debentures
held by their respective trusts, who in turn redeemed their respective preferred
securities.





*Securitized
Transition Bonds*





On June 11,
2002, JCP&L Transition Funding LLC (Issuer), a wholly owned limited
liability company of JCP&L, 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 does not
own nor did it purchase any of the transition bonds, which are included in
long-term debt on FirstEnergy's Consolidated Balance Sheets. The transition
bonds represent obligations only of the Issuer and are collateralized solely by
the equity and assets of the Issuer, which consist primarily of bondable
transition property. The bondable transition property is solely the property of
the Issuer.





Bondable transition
property represents the irrevocable right 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, as servicer, manages and
administers the bondable transition property, including the billing, collection
and remittance of the TBC, pursuant to a servicing agreement with the Issuer.





*Other Long-term
Debt*





Each of the
Companies has a first mortgage indenture under which it issues FMBs secured by a
direct first mortgage lien on substantially all of its property and franchises,
other than specifically excepted property. FirstEnergy and its subsidiaries have
various debt covenants under their respective financing arrangements. The most
restrictive of the debt covenants relate to the nonpayment of interest and/or
principal on debt and the maintenance of certain financial ratios. The fixed
charge ratio and debt-to-capitalization ratio covenants are applicable to only
financing arrangements of FirstEnergy, the Ohio Companies and Penn. There also
exist cross-default provisions among financing arrangements of FirstEnergy and
the Companies.





Based on the amount
of FMBs authenticated by the respective mortgage bond trustees through
December 31, 2004, the Companies' annual sinking fund requirements for all
FMBs issued under the various mortgage indentures amounts to $71 million. OE and
Penn expect to deposit funds with their respective mortgage bond trustees in
2005 that will then be withdrawn upon the surrender for cancellation of a like
principal amount of FMBs, specifically authenticated for such purposes against
unfunded property additions or against previously retired FMBs. This method can
result in minor increases in the amount of the annual sinking fund requirement.
JCP&L, Met-Ed and Penelec expect to fulfill their sinking fund obligations
by providing bondable property additions and/or previously retired FMBs to the
respective mortgage bond trustees.





72





Sinking fund
requirements for FMBs and maturing long-term debt (excluding capital leases) for
the next five years are:


***(In
millions)***


2005
    
    $
    9372006
    
    
    1,3272007
    
    
    4532008
    
    
    4702009
    
    
    285








Included in the
table above are amounts for various variable interest rate pollution control
bonds which have provisions by which individual debt holders have the option to
"put back" or require the respective debt issuer to redeem their debt at those
times when the interest rate may change prior to its maturity date. These
amounts are $442 million and $132 million in 2005 and 2008, respectively,
representing the next times the debt holders may exercise this provision.





The Companies'
obligations to repay certain pollution control revenue bonds are secured by
several series of FMBs. Certain pollution control revenue bonds are entitled to
the benefit of irrevocable bank LOCs of $299 million or noncancelable municipal
bond insurance policies of $922 million to pay principal of, or interest on, the
applicable pollution control revenue bonds. To the extent that drawings are made
under the LOCs or the policies, the Companies are entitled to a credit against
their obligation to repay those bonds. The Companies pay annual fees of 1.0% to
1.7% of the amounts of the LOCs to the issuing banks and 0.20% to 0.55% of the
amounts of the policies to the insurers and are obligated to reimburse the banks
or insurers, as the case may be, for any drawings thereunder.





FirstEnergy had
unsecured borrowings of $215 million as of December 31, 2004, under its $1
billion revolving credit facility agreement which expires June 22, 2007.
FirstEnergy currently pays an annual facility fee of 0.30% on the total credit
facility amount. FirstEnergy had no borrowings as of December 31, 2004
under a $375 million long-term revolving credit facility agreement, which
expires October 23, 2006. FirstEnergy currently pays an annual facility fee
of 0.50% on the total credit facility amount. The fees are subject to change
based on changes to FirstEnergy's credit ratings.





OE had no unsecured
borrowings as of December 31, 2004 under a $250 million long-term revolving
credit facility agreement, which expires May 12, 2005. OE currently pays an
annual facility fee of 0.20% on the total credit facility amount. OE had no
unsecured borrowings as of December 31, 2004 under a $125 million long-term
revolving credit facility, which expires October 23, 2006. OE currently
pays an annual facility fee of 0.25% on the total credit facility amount. The
fees are subject to change based on changes to OE's credit ratings.





OES Finance,
Incorporated, a wholly owned subsidiary of OE, had maintained certificates of
deposits pledged as collateral to secure reimbursement obligations relating to
certain LOCs supporting OE's obligations to lessors under the Beaver Valley Unit
2 sale and leaseback arrangements. In June 2004, these LOCs were replaced by a
new LOC, which did not require the collateral deposits. OE entered into a Credit
Agreement pursuant to which a standby LOC was issued in support of the
replacement LOCs and the issuer of the standby LOC obtained the right to pledge
or assign participations in OE's reimbursement obligations to a trust. The trust
then issued and sold trust certificates to institutional investors that were
designed to be the credit equivalent of an investment directly in OE. The
certificates of deposit were cancelled and FirstEnergy received cash proceeds of
$278 million in the third quarter of 2004.





CEI and TE have
unsecured LOCs of approximately $216 million in connection with the sale and
leaseback of Beaver Valley Unit 2 that expire in April 2005. CEI and TE are
jointly and severally liable for such LOCs. OE has LOCs of $294 million and $154
million in connection with the sale and leaseback of Beaver Valley Unit 2 and
Perry Unit 1, respectively.





**11.**
    **ASSET
      RETIREMENT OBLIGATIONS**





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





73





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 $1.078 billion as of December 31, 2004 and included
$1.063 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 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
for TMI-1. The abandoned TMI-2 is adjacent to TMI-1 and the units are expected
to be decommissioned concurrently. 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.





The Companies
maintain nuclear decommissioning trust funds that are legally restricted for
purposes of settling the nuclear decommissioning ARO. As of December 31,
2004, the fair value of the decommissioning trust assets was $1.583
billion.





The following table
describes the changes to the ARO balances during 2004 and 2003.





**2004**
    
    **2003****ARO
      Reconciliation**
    
    ***(In
      millions)***Balance at
      beginning of year
    
    $
    1,179
    
    $
    1,109Liabilities
      incurred
    
    
    --
    
    
    --Liabilities
      settled
    
    
    --
    
    
    --Accretion
    
    
    75
    
    
    70Revisions in
      estimated cash flows
    
    
    (176
    )
    
    --Balance at
      end of year
    
    $
    1,078
    
    $
    1,179





The following table
describes changes to the ARO for 2002, as if SFAS 143 had been adopted on
January 1, 2002.





**Adjusted
      ARO Reconciliation**
    
    **2002****(In
      millions)**Beginning
      balance as of January 1, 2002
    
    $
    1,042Accretion
    
    
    67Ending
      balance as of December 31, 2002
    
    $
    1,109





The following table
provides the effect on income as if SFAS 143 had been applied during
2002.





**Effect
      of the Change in Accounting****Principle
      Applied Retroactively**
    
    ***(In
      millions)***Reported net
      income
    
    $
    553Increase
      (Decrease):Elimination
      of decommissioning expense
    
    
    88Depreciation
      of asset retirement cost
    
    
    (3
    )Accretion of
      ARO liability
    
    
    (38
    )Non-regulated
      generation cost of removal component, net
    
    
    15Income tax
      effect
    
    
    (25
    )Net earnings
      increase
    
    
    37Net income
      adjusted
    
    $
    590Basic
      earnings per share of common stock:Net income as
      previously reported
    
    $
    1.89Adjustment
      for effect of change inaccounting
      principle applied retroactively
    
    
    0.12Net income
      adjusted
    
    $
    2.01Diluted
      earnings per share of common stock:Net income as
      previously reported
    
    $
    1.88Adjustment
      for effect of change inaccounting
      principle applied retroactively
    
    
    0.12Net income
      adjusted
    
    $
    2.00








74





**12.**
    **SHORT-TERM
      BORROWINGS AND BANK LINES OF CREDIT:**





Short-term
borrowings outstanding as of December 31, 2004, consisted of $29 million of
OE bank borrowings and $142 million of OES Capital, Incorporated borrowings. OES
Capital is a wholly owned subsidiary of OE whose borrowings are secured by
customer accounts receivable purchased from OE. OES Capital can borrow up to
$170 million under a receivables financing arrangement at rates based on certain
bank commercial paper and is required to pay an annual fee of 0.25% on the
amount of the entire finance limit. The receivables financing agreement expires
in October 2005. Penn, Met-Ed and Penelec have, through separate wholly owned
subsidiaries, receivables financing arrangements that provide a combined
borrowing capability of up to $180 million at rates based on bank commercial
paper rates. The financing arrangements require payment of an annual facility
fee of 0.30% on the entire finance limit. The receivables financing agreements
for Penn, Met-Ed and Penelec expire in March 2005. These receivables financing
arrangements are expected to be renewed prior to expiration.





OE has various
bi-lateral credit facilities with domestic banks that provide for borrowings of
up to $34 million under various interest rate options. To assure the
availability of these lines, OE is required to pay annual commitment fees that
vary from 0.20% to 0.25% of total lender commitments. These lines expire at
various times during 2005. The weighted average interest rates on short-term
borrowings outstanding as of December 31, 2004 and 2003 were 2.35% and
2.14%, respectively.





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 under
an asset-backed securitization agreement. The trust is a "qualified special
purpose entity" under SFAS 140, which provides it with certain rights relative
to the transferred assets. Transfers are made in return for an interest in the
trust (62% as of December 31, 2004), which is stated at fair value,
reflecting adjustments for anticipated credit losses. The fair value of CFC's
interest in the trust approximates the stated value of its retained interest in
the underlying receivables, after adjusting for anticipated credit losses,
because the average collection period is 27 days. Accordingly, subsequent
measurements of the retained interest under SFAS 115, (as an available-for-sale
financial instrument) result in no material change in value. Sensitivity
analyses reflecting 10% and 20% increases in the rate of anticipated credit
losses would not have significantly affected FirstEnergy's retained interest in
the pool of receivables through the trust.





Of the $222 million
sold to the trust and outstanding as of December 31, 2004, FirstEnergy
retained interests in $138 million of the receivables. Accordingly, receivables
recorded as other receivables on the Consolidated Balance Sheets were reduced by
approximately $84 million due to these sales. Collections of receivables
previously transferred to the trust and used for the purchase of new receivables
from CFC during 2004 totaled approximately $2.5 billion. CEI and TE processed
receivables for the trust and received servicing fees of approximately $4.8
million in 2004. Expenses associated with the factoring discount related to the
sale of receivables were $3.5 million in 2004.





**13.**
    **COMMITMENTS,
      GUARANTEES AND CONTINGENCIES:**





**(A)**
    **NUCLEAR
      INSURANCE-**





The Price-Anderson
Act limits the public liability relative to a single incident at a nuclear power
plant to $10.8 billion. The amount is covered by a combination of private
insurance and an industry retrospective rating plan. The Companies' maximum
potential assessment under the industry retrospective rating plan would be $402
million per incident but not more than $40 million in any one year for each
incident.





The Companies are
also insured under policies for each nuclear plant. Under these policies, up to
$2.75 billion is provided for property damage and decontamination costs. The
Companies have also obtained approximately $1.5 billion of insurance coverage
for replacement power costs. Under these policies, the Companies can be assessed
a maximum of approximately $67.5 million for incidents at any covered nuclear
facility occurring during a policy year which are in excess of accumulated funds
available to the insurer for paying losses.





The Companies
intend to maintain insurance against nuclear risks as long as it is available.
To the extent that replacement power, property damage, decontamination, repair
and replacement costs and other such costs arising from a nuclear incident at
any of the Companies' plants exceed the policy limits of the insurance in effect
with respect to that plant, to the extent a nuclear incident is determined not
to be covered by the Companies' insurance policies, or to the extent such
insurance becomes unavailable in the future, the Companies would remain at risk
for such costs.





**(B)**
    **GUARANTEES
      AND OTHER ASSURANCES-**





As part of normal
business activities, FirstEnergy enters into various agreements on behalf of its
subsidiaries to provide financial or performance assurances to third parties.
Such agreements include contract guarantees, surety bonds and ratings contingent
collateralization provisions. As of December 31, 2004, outstanding
guarantees and other assurances aggregated approximately $2.4 billion and
included contract guarantees ($1.0 billion), surety bonds ($0.3 billion) and LOC
($1.1 billion).





75


FirstEnergy
guarantees energy and energy-related payments of its subsidiaries involved in
energy commodity 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 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 December 31, 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 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 posting of cash
collateral or provision of an LOC may be required of the subsidiary. The
following table summarizes collateral provisions as of December 31,
2004:





**Collateral
      Paid**
    
    
    
    **Remaining****Collateral
      Provisions**
    
    **Exposure**
    
    **Cash**
    
    **LOC**
    
    **Exposure****(1)*****(In
      millions)***Credit rating
      downgrade
    
    $
    349
    
    $
    162
    
    $
    18
    
    $
    169Adverse
      Event
    
    
    135
    
    
    --
    
    
    22
    
    
    113Total
    
    $
    484
    
    $
    162
    
    $
    40
    
    $
    282




(1)
    As of
      February 7, 2005, the total exposure decreased to $476 million and the
      remaining exposure increased to
      $290 million
      - net of $146 million of cash collateral and $40 million of LOC collateral
      provided by counterparties.





Most of
FirstEnergy's surety bonds are backed by various indemnities common within the
insurance industry. Surety bonds and related FirstEnergy guarantees of $279
million provide additional assurance to outside parties that contractual and
statutory obligations will be met in a number of areas including construction
jobs, environmental commitments and various retail transactions.





FirstEnergy has
also guaranteed the obligations of the operators of the TEBSA project, up to a
maximum of $6 million (subject to escalation) under the project's operations and
maintenance agreement. In connection with the sale of TEBSA in January 2004, the
purchaser indemnified FirstEnergy against any loss under this guarantee.
FirstEnergy has also provided an LOC (currently at $47 million), which is
renewable and declines yearly based upon the senior outstanding debt of TEBSA.





**(C)**
    **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
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 $430 million for 2005 through 2007.





*Clean Air Act
Compliance*


The Companies are
required to meet federally approved SO 2 regulations.
Violations of such regulations can result in shutdown of the generating unit
involved and/or civil or criminal penalties of up to $32,500 for each day the
unit is in violation. The EPA has an interim enforcement policy for
SO 2 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 SO 2 reduction
requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur
fuel, generating more electricity from lower-emitting plants, and/or using
emission allowances. NO x reductions
required by the 1990 Amendments are being achieved through combustion controls
and the generation of more electricity at lower-emitting plants. In September
1998, the EPA finalized regulations requiring additional NO x reductions from
the Companies' facilities. The EPA's NO x Transport Rule
imposes uniform reductions of NO x emissions (an
approximate 85 percent reduction in utility plant NO x emissions from
projected 2007 emissions) across a region of nineteen states (including
Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based
on a conclusion that such NO x emissions are
contributing significantly to ozone levels in the eastern United States. The
Companies believe their facilities are also complying with the NO x budgets
established under State Implementation Plans (SIPs) through combustion controls
and post-combustion controls, including Selective Catalytic Reduction and
Selective Non-Catalytic Reduction systems, and/or using emission
allowances.





76


*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 Michigan, New Jersey,
Ohio and Pennsylvania) and the District of Columbia based on proposed findings
that air pollution emissions from 29 eastern states and the District of Columbia
significantly contribute to nonattainment of the NAAQS for fine particles and/or
the "8-hour" ozone NAAQS in other states. The EPA has proposed the Interstate
Air Quality Rule to "cap-and-trade" NO x and SO 2 emissions in two
phases (Phase I in 2010 and Phase II in 2015). According to the EPA,
SO 2 emissions would be
reduced by approximately 3.6 million tons annually by 2010, across states
covered by the rule, with reductions ultimately reaching more than 5.5 million
tons annually. NO x emission
reductions would measure about 1.5 million tons in 2010 and 1.8 million tons in
2015. The future cost of compliance with these proposed regulations 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 SO 2 and NO x emission caps under
the EPA's proposed Interstate Air Quality Rule. Phase II of the mercury
cap-and-trade program would be implemented in 2018 to cap nationwide mercury
emissions from coal-fired power plants at 15 tons per year. The EPA has agreed
to choose between these two options and issue a final rule by March 15,
2005. The future cost of compliance with these regulations may be
substantial.





*W. H. Sammis
Plant*





In 1999 and 2000,
the EPA issued NOV or Compliance Orders to nine utilities covering 44 power
plants, including the W. H. Sammis Plant, which is owned by OE and Penn. In
addition, the U.S. Department of Justice filed eight civil complaints against
various investor-owned utilities, which included a complaint against OE and Penn
in the U.S. District Court for the Southern District of Ohio. These cases are
referred to as New Source Review cases. The NOV and complaint allege violations
of the Clean Air Act based on operation and maintenance of the W. H. Sammis
Plant dating back to 1984. The complaint requests permanent injunctive relief to
require the installation of "best available control technology" and civil
penalties of up to $27,500 per day of violation. On August 7, 2003, the
United States District Court for the Southern District of Ohio ruled that 11
projects undertaken at the W. H. Sammis Plant between 1984 and 1998 required
pre-construction permits under the Clean Air Act. The ruling concludes the
liability phase of the case, which deals with applicability of Prevention of
Significant Deterioration provisions of the Clean Air Act. The remedy phase of
the trial to address civil penalties and what, if any, actions should be taken
to further reduce emissions at the plant has been delayed without rescheduling
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
December 31, 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.





77


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
December 31, 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 as of
December 31, 2004. The Companies accrue environmental liabilities only when
they conclude that it is probable that they have an obligation for such costs
and can reasonably determine the amount of such costs. Unasserted claims are
reflected in the Companies’ determination of environmental liabilities and are
accrued in the period that they are both probable and reasonably
estimable.


*Climate
Change*





In December 1997,
delegates to the United Nations' climate summit in Japan adopted an agreement,
the Kyoto Protocol (Protocol), to address global warming by reducing the amount
of man-made greenhouse gases emitted by developed countries by 5.2% from 1990
levels between 2008 and 2012. The United States signed the Protocol in 1998 but
it failed to receive the two-thirds vote of the United States 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 percent through
2012.





The Companies
cannot currently estimate the financial impact of climate change policies,
although the potential restrictions on CO 2 emissions could
require significant capital and other expenditures. However, the CO 2 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-CO 2 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 require material capital
expenditures.





**(D)**
    **OTHER LEGAL PROCEEDINGS**





*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 product 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 December 31, 2004.





78


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 real-time diagnostic support. The final report is publicly
available through the Department of Energy’s website (www.doe.gov). FirstEnergy
believes that the final report does not provide a complete and comprehensive
picture of the conditions that contributed to the August 14, 2003 power
outages and that it does not adequately address the underlying causes of the
outages. FirstEnergy remains convinced that the outages cannot be explained by
events on any one utility's system. The final report 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, ECAR, and other parties to correct the
causes of the August 14, 2003 power outage. 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 with minor exceptions noted by
FirstEnergy (see Note 9). 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, FirstEnergy
does not believe that any incremental expenses associated with additional
initiatives undertaken during 2004 will have a material effect on its continuing
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 December 31, 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. The other two cases were
appealed. One case was dismissed and no further appeal was sought. The remaining
case is pending. 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 timetable for a
decision on the motion to dismiss has been established by the Court. 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 initiated against the Companies. In particular, if FirstEnergy or its
subsidiaries were ultimately determined to have legal liability in connection
with these proceedings, it could have a material adverse effect on FirstEnergy's
or its subsidiaries' financial condition 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 Nuclear Power Station.
On December 10, 2004, FirstEnergy received a letter from the United States
Attorney's Office stating that FENOC is a target of the federal grand jury
investigation into alleged false statements made to the NRC in the Fall of 2001
in response to NRC Bulletin 2001-01. The letter also said that the designation
of FENOC as a target indicates that, in the view of the prosecutors assigned to
the matter, it is likely that
federal charges will be returned against FENOC by
the grand jury. On February 10, 2005, FENOC received an additional subpoena for
documents related to root cause reports regarding reactor head degradation and
the assessment of reactor head management issues at Davis-Besse.





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. 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.





79


On August 12,
2004, the NRC notified FENOC 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. FENOC operates the Perry Nuclear Power Plant,
which is either owned or leased by OE, CEI, TE and Penn. Although the NRC noted
that the plant continues to operate safely, the agency has indicated that its
increased oversight will include an extensive NRC team inspection to assess the
equipment problems and the sufficiency of FENOC's corrective actions. The
outcome of these matterscould include NRC
enforcement action or other impacts on operating authority. As a result, these
matters could have a material adverse effect on FirstEnergy's or its
subsidiaries' financial condition.




*Other Legal
Matters*





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





Various legal
proceedings alleging violations of federal securities laws and related state
laws were filed against FirstEnergy in connection with, among other things, the
restatements in August 2003 by FirstEnergy and 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 paid $71.92
million, based on a contractual pre-allocation, and FirstEnergy paid $17.98
million, which resulted in an after-tax charge against FirstEnergy's second
quarter 2004 earnings of $11 million or $0.03 per share of common stock (basic
and diluted). On December 30, 2004, the court approved the
settlement.





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, have
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. On
December 30, 2004, FirstEnergy received a second subpoena asking for
documents relating to issues raised during the SEC's PUHCA examination.
FirstEnergy has cooperated fully with the informal inquiry and will continue to
do so with the formal investigation.





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





**14.**
    **SEGMENT
      INFORMATION:**





FirstEnergy has
three reportable segments: regulated services, competitive electric energy
services and facilities (HVAC) services. The aggregate “Other” segments do not
individually meet the criteria to be considered a reportable segment. “Other”
consists of international businesses that have subsequently been divested, MYR
(a construction service company); natural gas operations and telecommunications
services. The assets and revenues for the other business operations are below
the quantifiable threshold for operating segments for separate disclosure as
“reportable segments.” 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 electric energy services business segment
primarily consists of the subsidiaries (FES, FGCO and FENOC) that sell
electricity in deregulated markets and operate the generation facilities of OE,
CEI, TE and Penn resulting from the deregulation of the Companies' electric
generation business (see Note 2(A) - Accounting for the Effects of
Regulation).





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 regulated
services segment assets include generating units that are leased to the
competitive electric energy services. Its internal revenues represent the rental
revenues for the generating unit leases.





The competitive
electric energy services segment has responsibility for FirstEnergy generation
operations as discussed under Note 2(A). Its net income is primarily
derived from revenues from all electric generation sales revenues consisting of
generation services to regulated franchise customers who have not chosen an
alternative generation supplier, retail sales in deregulated markets and all
domestic unregulated electricity sales in the retail and wholesale markets and
the related costs of electricity generation and sourcing of commodity
requirements. Its net income also reflects the expense of the intersegment
generating unit leases discussed above and property tax amounts related to those
generating units.





80


Segment reporting
for 2003 and 2002 was reclassified to conform with the current year business
segment organization and operations emphasizing FirstEnergy's regulated electric
businesses and competitive electric energy operations. A previous reportable
segment was the more expansive competitive services segment whose aggregate
operations consisted of FirstEnergy generation operations, natural gas commodity
sales, providing local and long-distance phone service and other competitive
energy related businesses such as facilities services and construction service
(MYR) which was viewed as offering a comprehensive menu of energy related
services. Management's focus is on its core electric business. This has resulted
in a change in performance review analysis from an aggregate view of all
competitive services operations to a focus on its competitive electric energy
operations. During FirstEnergy's periodic review of reportable segments under
SFAS 131, that change resulted in the revision of reportable segments to the
separate reporting of competitive electric energy operations, facilities
services and including all other competitive services operations in the "Other"
segment. Facilities services is being disclosed as a reporting segment due to
the subsidiaries qualifying as held for sale (see Note 2 (H)). In addition,
certain amounts (including transmission and congestion charges) were
reclassified among purchased power, other operating costs and depreciation and
amortization to conform with the current year presentation of generation
commodity costs. Interest expense on holding company debt and corporate support
services revenues and expenses are now included in "Reconciling Items" and
"Other" includes those operating segment results described above.





81








**Segment
Financial Information**





**Competitive****Electric****Regulated**
    
    **Energy**
    
    **Facilities**
    
    
    
    **Reconciling****Services**
    
    **Services**
    
    **Services**
    
    **Other**
    
    **Adjustments**
    
    **Consolidated*****(In
      millions)*****2004**External
      revenues
    
    $
    5,395
    
    $
    6,204
    
    $
    398
    
    $
    451
    
    $
    5
    
    $
    12,453Internal
      revenues
    
    
    318
    
    
    --
    
    
    --
    
    
    --
    
    
    (318
    )
    
    --Total
      revenues
    
    
    5,713
    
    
    6,204
    
    
    398
    
    
    451
    
    
    (313
    )
    
    12,453Depreciation
      and amortization
    
    
    1,422
    
    
    35
    
    
    5
    
    
    3
    
    
    34
    
    
    1,499Goodwill
      impairment
    
    
    --
    
    
    --
    
    
    36
    
    
    --
    
    
    --
    
    
    36Net
      interest charges
    
    
    363
    
    
    37
    
    
    1
    
    
    14
    
    
    252
    
    
    667Income
      taxes
    
    
    740
    
    
    72
    
    
    (10
    )
    
    (24
    )
    
    (107
    )
    
    671Income
      before discontinued operations
    
    
    1,015
    
    
    104
    
    
    (36
    )
    
    41
    
    
    (250
    )
    
    874Discontinued
      operations
    
    
    --
    
    
    --
    
    
    --
    
    
    4
    
    
    --
    
    
    4Net
      income
    
    
    1,015
    
    
    104
    
    
    (36
    )
    
    45
    
    
    (250
    )
    
    878Total
      assets
    
    
    28,341
    
    
    1,488
    
    
    135
    
    
    625
    
    
    479
    
    
    31,068Total
      goodwill
    
    
    5,951
    
    
    24
    
    
    --
    
    
    75
    
    
    --
    
    
    6,050Property
      additions
    
    
    572
    
    
    246
    
    
    3
    
    
    4
    
    
    21
    
    
    846**2003**External
      revenues
    
    $
    5,253
    
    $
    5,487
    
    $
    327
    
    $
    564
    
    $
    44
    
    $
    11,675Internal
      revenues
    
    
    319
    
    
    --
    
    
    --
    
    
    --
    
    
    (319
    )
    
    --Total
      revenues
    
    
    5,572
    
    
    5,487
    
    
    327
    
    
    564
    
    
    (275
    )
    
    11,675Depreciation
      and amortization
    
    
    1,423
    
    
    29
    
    
    --
    
    
    2
    
    
    38
    
    
    1,492Goodwill
      impairment
    
    
    --
    
    
    --
    
    
    117
    
    
    --
    
    
    --
    
    
    117Net
      interest charges
    
    
    493
    
    
    44
    
    
    1
    
    
    107
    
    
    164
    
    
    809Income
      taxes
    
    
    779
    
    
    (222
    )
    
    (35
    )
    
    (18
    )
    
    (96
    )
    
    408Income
      before discontinued operations andcumulative
      effect of accounting change
    
    
    1,063
    
    
    (320
    )
    
    (75
    )
    
    (64
    )
    
    (180
    )
    
    424Discontinued
      operations
    
    
    --
    
    
    --
    
    
    (6
    )
    
    (97
    )
    
    --
    
    
    (103
    )Cumulative
      effect of accounting change
    
    
    101
    
    
    --
    
    
    --
    
    
    1
    
    
    --
    
    
    102Net
      income
    
    
    1,164
    
    
    (320
    )
    
    (81
    )
    
    (160
    )
    
    (180
    )
    
    423Total
      assets
    
    
    29,789
    
    
    1,423
    
    
    166
    
    
    912
    
    
    620
    
    
    32,910Total
      goodwill
    
    
    5,993
    
    
    24
    
    
    36
    
    
    75
    
    
    --
    
    
    6,128Property
      additions
    
    
    434
    
    
    335
    
    
    4
    
    
    9
    
    
    74
    
    
    856**2002**External
      revenues
    
    $
    5,298
    
    $
    4,825
    
    $
    383
    
    $
    907
    
    $
    40
    
    $
    11,453Internal
      revenues
    
    
    318
    
    
    --
    
    
    --
    
    
    --
    
    
    (318
    )
    
    --Total
      revenues
    
    
    5,616
    
    
    4,825
    
    
    383
    
    
    907
    
    
    (278
    )
    
    11,453Depreciation
      and amortization
    
    
    1,413
    
    
    24
    
    
    6
    
    
    2
    
    
    34
    
    
    1,479Net
      interest charges
    
    
    588
    
    
    43
    
    
    2
    
    
    134
    
    
    189
    
    
    956Income
      taxes
    
    
    722
    
    
    (88
    )
    
    2
    
    
    (14
    )
    
    (108
    )
    
    514Income
      before discontinued operations
    
    
    962
    
    
    (170
    )
    
    --
    
    
    21
    
    
    (195
    )
    
    618Discontinued
      operations
    
    
    --
    
    
    --
    
    
    3
    
    
    (68
    )
    
    --
    
    
    (65
    )Net
      income
    
    
    962
    
    
    (170
    )
    
    3
    
    
    (47
    )
    
    (195
    )
    
    553Total
      assets
    
    
    30,494
    
    
    1,340
    
    
    402
    
    
    1,606
    
    
    544
    
    
    34,386Total
      goodwill
    
    
    5,993
    
    
    24
    
    
    196
    
    
    65
    
    
    --
    
    
    6,278Property
      additions
    
    
    490
    
    
    391
    
    
    6
    
    
    9
    
    
    102
    
    
    998





Reconciling
adjustments to segment operating results from internal management reporting to
consolidated external financial reporting primarily consist of interest expense
related to holding company debt, corporate support services revenues and
expenses, fuel marketing revenues, which are reflected as reductions to expenses
for internal management reporting purposes, and elimination of intersegment
transactions.








**Products
      and Services***


**Energy
      Related****Electricity**
    
    **Sales
      and****Year**
    
    **Sales**
    
    **Services*****(In
      millions)***2004
    
    $
    10,831
    
    $
    7452003
    
    
    10,205
    
    
    7662002
    
    
    9,656
    
    
    904





* See Note
2(J) for discussion of discontinued operations.





82





**Geographic
Information**





Following the sales
of international operations in 2002 through January of 2004, less than one
percent of FirstEnergy's revenues and assets were in foreign countries in 2003
and 2004. See Note 8 for a discussion of the divestitures.





**15.**
    **NEW ACCOUNTING STANDARDS AND
INTERPRETATIONS**





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





In December 2004,
the FASB issued this Statement amending APB 29, which was based on the principle
that nonmonetary assets should be measured based on the fair value of the assets
exchanged. The guidance in APB 29 included certain exceptions to that principle.
SFAS 153 eliminates the exception from fair value measurement for nonmonetary
exchanges of similar productive assets and replaces it with an exception for
exchanges that do not have commercial substance. This Statement specifies that a
nonmonetary exchange has commercial substance if the future cash flows of the
entity are expected to change significantly as a result of the exchange. The
provisions of this statement are effective for nonmonetary exchanges occurring
in fiscal periods beginning after June 15, 2005 and are to be applied
prospectively. FirstEnergy is currently evaluating this standard but does not
expect it to have a material impact on the financial statements.





*SFAS 123
(revised 2004), “Share-Based Payment”*





In December 2004,
the FASB issued this revision to SFAS 123, which requires expensing stock
options in the financial statements. Important to applying the new standard is
understanding how to (1) measure the fair value of stock-based compensation
awards and (2) recognize the related compensation cost for those awards. For an
award to qualify for equity classification, it must meet certain criteria in
SFAS 123(R). An award that does not meet those criteria will be classified as a
liability and remeasured each period. SFAS 123(R) retains SFAS 123's
requirements on accounting for income tax effects of stock-based compensation.
The effective date for FirstEnergy is July 1, 2005 and the Company will be
applying modified prospective application, without restatement of prior interim
periods. Any potential cumulative adjustments have not been determined.
FirstEnergy uses the Black-Scholes option-pricing model to value options and
will continue to do so upon adoption of SFAS 123(R). The impacts of the fair
value recognition provisions of SFAS 123 on FirstEnergy’s net income and
earnings per share for 2002 through 2004 are disclosed in Note 4. FirstEnergy is
considering alternative compensation strategies in conjunction with the adoption
of SFAS 123(R).





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





In November 2004,
the FASB issued this statement to clarify the accounting for abnormal amounts of
idle facility expense, freight, handling costs and wasted material (spoilage).
Previous guidance stated that in some circumstances these costs may be “so
abnormal” that they would require treatment as current period costs. SFAS 151
requires abnormal amounts for these items to always be recorded as current
period costs. In addition, this Statement requires that allocation of fixed
production overheads to the cost of conversion be based on the normal capacity
of the production facilities. The provisions of this statement are effective for
inventory costs incurred by FirstEnergy after June 30, 2005. FirstEnergy is
currently evaluating this standard but does not expect it to have a material
impact on the financial statements.





*EITF Issue No.
03-1, "The Meaning of Other-Than-Temporary Impairment 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.




83





*FSP
      109-1. “Application of FASB Statement No. 109, Accounting for Income
      Taxes, to the Tax Deduction and Qualified Production Activities Provided
      by the American Jobs Creation Act of
2004”*




Issued in December
2004, FSP 109-1 provides guidance related to the provision within the American
Jobs Creation Act of 2004 (Act) that provides a tax deduction on qualified
production activities. The Act includes a tax deduction of up to 9 percent (when
fully phased-in) of the lesser of (a) “qualified production activities income,”
as defined in the Act, or (b) taxable income (after the deduction for the
utilization of any net operating loss carryforwards). This tax deduction is
limited to 50 percent of W-2 wages paid by the taxpayer. The FASB believes that
the deduction should be accounted for as a special deduction in accordance with
SFAS No. 109, “Accounting for Income Taxes.” FirstEnergy is currently evaluating
this FSP but does not expect it to have a material impact on the Company's
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 3.





**16.**
    **SUMMARY
      OF QUARTERLY FINANCIAL DATA (UNAUDITED):**





The following
summarizes certain consolidated operating results by quarter for 2004 and 2003.
Certain financial results have been reclassified from amounts previously
reported due to FES' natural gas business qualifying as held for sale in
accordance with SFAS 144 as discussed in Note 2(J).





**March
      31,**
    
    **June
      30,**
    
    **September
      30,**
    
    **December
      31,****Three
      Months Ended**
    
    **2004**
    
    **2004**
    
    **2004**
    
    **2004*****(In
      millions, except per share amounts)***Revenues
    
    $
    3,027
    
    $
    3,041
    
    $
    3,435
    
    $
    2,950Expenses
    
    
    2,568
    
    
    2,481
    
    
    2,771
    
    
    2,421Income
      Before Interest and Income Taxes
    
    
    459
    
    
    560
    
    
    664
    
    
    529Net
      Interest Charges
    
    
    171
    
    
    180
    
    
    151
    
    
    165Income
      Taxes
    
    
    115
    
    
    177
    
    
    215
    
    
    163Income
      Before Discontinued Operations
    
    
    173
    
    
    203
    
    
    298
    
    
    201Discontinued
      Operations (Net of Income Taxes)
    
    
    1
    
    
    1
    
    
    1
    
    
    1Net
      Income
    
    $
    174
    
    $
    204
    
    $
    299
    
    $
    202Basic
      Earnings Per Share of Common Stock:Before
      Discontinued Operations
    
    $
    0.53
    
    $
    0.62
    
    $
    0.91
    
    $
    0.61Discontinued
      Operations
    
    
    --
    
    
    --
    
    
    --
    
    
    --Basic
      Earnings Per Share of Common Stock
    
    $
    0.53
    
    $
    0.62
    
    $
    0.91
    
    $
    0.61Diluted
      Earnings Per Share of Common Stock:Before
      Discontinued Operations
    
    $
    0.53
    
    $
    0.62
    
    $
    0.91
    
    $
    0.61Discontinued
      Operations
    
    
    --
    
    
    --
    
    
    --
    
    
    --Diluted
      Earnings Per Share of Common Stock
    
    $
    0.53
    
    $
    0.62
    
    $
    0.91
    
    $
    0.61








**March
      31,**
    
    **June
      30,**
    
    **September
      30,**
    
    **December
      31,****Three
      Months Ended**
    
    **2003**
    
    **2003**
    
    **2003**
    
    **2003*****(In
      millions, except per share amounts)***Revenues
    
    $
    2,981
    
    $
    2,728
    
    $
    3,317
    
    $
    2,649Expenses
    
    
    2,571
    
    
    2,488
    
    
    2,833
    
    
    2,310Claim
      Settlement (Note 8)
    
    
    --
    
    
    --
    
    
    --
    
    
    168Income
      Before Interest and Income Taxes
    
    
    410
    
    
    240
    
    
    484
    
    
    507Net
      Interest Charges
    
    
    205
    
    
    205
    
    
    200
    
    
    199Income
      Taxes
    
    
    93
    
    
    21
    
    
    134
    
    
    160Income
      Before Discontinued Operations andCumulative
      Effect of Accounting Change
    
    
    112
    
    
    14
    
    
    150
    
    
    148Discontinued
      Operations (Net of Income Taxes)
    
    
    5
    
    
    (72
    )
    
    2
    
    
    (38
    )Cumulative
      Effect of Accounting Change(Net
      of Income Taxes)
    
    
    102
    
    
    --
    
    
    --
    
    
    --Net
      Income (Loss)
    
    $
    219
    
    $
    (58
    )
    $
    152
    
    $
    110Basic
      Earnings (Loss) Per Share of Common Stock:Before
      Discontinued Operations and CumulativeEffect
      of Accounting Change
    
    $
    0.38
    
    $
    0.05
    
    $
    0.51
    
    $
    0.45Discontinued
      Operations
    
    
    0.01
    
    
    (0.25
    )
    
    --
    
    
    (0.12
    )Cumulative
      Effect of Accounting Change
    
    
    0.35
    
    
    --
    
    
    --
    
    
    --Basic
      Earnings (Loss) Per Share of Common Stock
    
    $
    0.74
    
    $
    (0.20
    )
    $
    0.51
    
    $
    0.33Diluted
      Earnings (Loss) Per Share of Common Stock:Before
      Discontinued Operations and CumulativeEffect
      of Accounting Change
    
    $
    0.38
    
    $
    0.05
    
    $
    0.50
    
    $
    0.45Discontinued
      Operations
    
    
    0.01
    
    
    (0.25
    )
    
    --
    
    
    (0.12
    )Cumulative
      Effect of Accounting Change
    
    
    0.35
    
    
    --
    
    
    --
    
    
    --Diluted
      Earnings (Loss) Per Share of Common Stock
    
    $
    0.74
    
    $
    (0.20
    )
    $
    0.50
    
    $
    0.33








84





Results in the
second quarter of 2004 included FirstEnergy’s sale of its 50 percent interest in
GLEP, which produced an after-tax loss of $7 million, or $0.02 per share (see
Note 8). Third quarter 2004 results were impacted by a $17 million net-of-tax,
or $0.05 per share, charge for losses and impairments relating to the
divestiture of certain non-core, technology-related investments. Fourth quarter
2004 results included a $37 million net-of-tax, or $0.11 per share, non-cash
charge for impairment of goodwill and other assets of FSG as required by SFAS
142 and SFAS 144 (see Note 2 (H)).





The net loss for
the second quarter of 2003 included a charge resulting from the NJBPU's decision
to disallow recovery by JCP&L of $153 million in deferred energy costs and a
$67 million non-cash charge (no tax benefit recognized) from the abandonment of
operations in Argentina.





Results for the
fourth quarter of 2003 included a $33 million after-tax loss from the
divestiture of assets in Bolivia reported as discontinued operations and a $26
million impairment of the equity TEBSA investment in Columbia included in
continuing operations. The fourth quarter 2003 results also include a $170
million gain ($168 million net of expenses) from the NRG Energy Inc. settlement
claim.





85