**JERSEY
CENTRAL POWER & LIGHT COMPANY**





**2004 ANNUAL
REPORT TO STOCKHOLDERS**











Jersey Central
Power & Light Company is a wholly owned electric utility operating
subsidiary of FirstEnergy Corp. It engages in the distribution and sale of
electric energy in an area of approximately 3,300 square miles in New Jersey. It
also engages in the sale, purchase and interchange of electric energy with other
electric companies. The area it serves has a population of approximately 2.5
million.




















**Contents**
    
    **Page**Glossary of
      Terms
    
    
    i-iiManagement
      Reports
    
    
    1Report of
      Independent Registered Public Accounting Firm
    
    
    2Selected
      Financial Data
    
    
    3Management's
      Discussion and Analysis
    
    
    4-14Consolidated
      Statements of Income
    
    
    15Consolidated
      Balance Sheets
    
    
    16Consolidated
      Statements of Capitalization
    
    
    17Consolidated
      Statements of Common Stockholder's Equity
    
    
    18Consolidated
      Statements of Preferred Stock
    
    
    18Consolidated
      Statements of Cash Flows
    
    
    19Consolidated
      Statements of Taxes
    
    
    20Notes to
      Consolidated Financial Statements
    
    
    21-36



















**GLOSSARY OF
TERMS**





The following
abbreviations and acronyms are used in this report to identify Jersey Central
Power & Light Company and its affiliates:





ATSI
    American
      Transmission Systems, Inc., owns and operates transmission
      facilitiesCEI
    The Cleveland
      Electric Illuminating Company, an affiliated Ohio electric
      utilityCompanies
    OE, CEI, TE,
      Penn, JCP&L, Met-Ed and PenelecFES
    FirstEnergy
      Solutions Corp., provides energy-related products and
    servicesFESC
    FirstEnergy
      Service Company, provides legal, financial, and other corporate support
      servicesFirstEnergy
    FirstEnergy
      Corp., a registered public utility holding companyGPU
    GPU, Inc.,
      former parent of JCP&L, Met-Ed and Penelec, which merged with
      FirstEnergy on
      November 7,
      2001GPUS
    GPU Service
      Company, previously provided corporate support servicesJCP&L
    Jersey
      Central Power & Light CompanyJCP&L
      Transition
    JCP&L
      Transition Funding LLC, a Delaware limited liability company and issuer of
      transition
      BondsMet-Ed
    Metropolitan
      Edison Company, an affiliated Pennsylvania electric
  utilityOE
    Ohio Edison
      Company, an affiliated Ohio electric utilityPenelec
    Pennsylvania
      Electric Company, an affiliated Pennsylvania electric
    utilityPenn
    Pennsylvania
      Power Company, an affiliated Pennsylvania electric utilityTE
    The Toledo
      Edison Company, an affiliated Ohio electric utilityThe following
      abbreviations and acronyms are used to identify frequently used terms in
      this report:AOCL
    Accumulated
      Other Comprehensive LossAPB
      29
    APB Opinion
      No. 29, "Accounting for Stock Issued to Employees"ARO
    Asset
      Retirement ObligationBGS
    Basic
      Generation ServiceCTC
    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”EITF97-4
    EITF Issue
      No. 97-4 “Deregulation of the Pricing
      of Electricity - Issues Related to the Application of FASB Statements No.
      71 and 101”FASB
    Financial
      Accounting Standards BoardFERC
    Federal
      Energy Regulatory CommissionFIN
      46R
    FASB
      Interpretation (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 IssueNo.
      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
      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 StatesIRS
    Internal
      Revenue ServiceMedicare
      Act
    Medicare
      Prescription Drug, Improvement and Modernization Act of
    2003MISO
    Midwest
      Independent Transmission System Operator, Inc.Moody’s
    Moody’s
      Investors ServiceMTC
    Market
      Transition ChargeMW
    MegawattsNERC
    North
      American Electric Reliability CouncilNJBPU
    New Jersey
      Board of Public UtilitiesNUG
    Non-Utility
      GenerationOCI
    Other
      Comprehensive IncomeOPEB
    Other
      Post-Employment BenefitsPJM
    PJM
      Interconnection L.L.C.





**GLOSSARY OF
TERMS, Cont’d**








PRP
    Potentially
      Responsible PartyPUCO
    Public
      Utilities Commission of OhioPUHCA
    Public
      Utility Holding Company ActS&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
      133
    SFAS No. 133,
      “Accounting for Derivative Instruments
      and Hedging Activities”SFAS
      140
    SFAS No. 140,
      “Accounting for Transfers and
      Servicing of Financial Assets and
      Extinguishment
      of Liabilities”SFAS
      142
    SFAS No. 142,
      "Goodwill and Other Intangible Assets"SFAS
      143
    SFAS No. 143,
      "Accounting for Asset Retirement Obligations"SFAS
      144
    SFAS No. 144,
      "Accounting for the Impairment or Disposal of Long-Lived
      Assets"SPE
    Special
      Purpose EntityTBC
    Transition
      Bond ChargeTMI-1
    Three Mile
      Island Unit 1TMI-2
    Three Mile
      Island Unit 2VIE
    Variable
      Interest Entity










ii





**MANAGEMENT
REPORTS**





*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 registered public accounting firms'
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.





*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 Jersey
Central


Power & Light
Company:





We have completed an
integrated audit of Jersey Central Power & Light Company’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 stockholder’s equity, preferred stock, cash
flows and taxes present fairly, in all material respects, the financial position
of Jersey Central Power & Light Company 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 9 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 6 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











**JERSEY
CENTRAL POWER & LIGHT COMPANY**





**SELECTED
FINANCIAL DATA**








**Nov.
      7 -**
    
    
    **Jan.
      1 -****2004**
    
    **2003**
    
    **2002**
    
    **Dec.
      31, 2001**
    
    
    **Nov.
      6, 2001**
    
    **2000*****(Dollars
      in thousands)***Operating
      Revenues
    
    $
    2,206,987
    
    $
    2,359,646
    
    $
    2,328,415
    
    $
    282,902
    
    
    $
    1,838,638
    
    $
    1,979,297Operating
      Income
    
    $
    183,909
    
    $
    146,775
    
    $
    335,209
    
    $
    43,666
    
    
    $
    292,847
    
    $
    283,227Net Income
    
    $
    111,639
    
    $
    68,017
    
    $
    251,895
    
    $
    30,041
    
    
    $
    34,467
    
    $
    210,812Earnings on
      Common Stock
    
    $
    111,139
    
    $
    68,129
    
    $
    253,359
    
    $
    29,343
    
    
    $
    29,920
    
    $
    203,908Total
      Assets
    
    $
    7,291,184
    
    $
    7,579,044
    
    $
    8,052,755
    
    $
    8,039,998
    
    
    
    
    
    $
    6,009,054**Capitalization
      as of December 31:**Common
      Stockholder’s Equity
    
    $
    3,155,362
    
    $
    3,153,974
    
    $
    3,274,069
    
    $
    3,163,701
    
    
    
    
    
    $
    1,459,260Preferred
      Stock-Not Subject
      to Mandatory Redemption
    
    
    12,649
    
    
    12,649
    
    
    12,649
    
    
    12,649
    
    
    
    
    
    
    12,649Subject to
      Mandatory Redemption
    
    
    --
    
    
    --
    
    
    --
    
    
    44,868
    
    
    
    
    
    
    51,500Company-Obligated
      Mandatorily
      Redeemable
      Preferred Securities
    
    
    --
    
    
    --
    
    
    125,244
    
    
    125,250
    
    
    
    
    
    
    125,000Long-Term
      Debt
    
    
    1,238,984
    
    
    1,095,991
    
    
    1,210,446
    
    
    1,224,001
    
    
    
    
    
    
    1,093,987Total
      Capitalization
    
    $
    4,406,995
    
    $
    4,262,614
    
    $
    4,622,408
    
    $
    4,570,469
    
    
    
    
    
    $
    2,742,396**Capitalization
      Ratios:**Common
      Stockholder’s Equity
    
    
    71.6
    %
    
    74.0
    %
    
    70.8
    %
    
    69.2
    %
    
    
    
    
    
    53.2
    %Preferred
      Stock-Not Subject
      to Mandatory Redemption
    
    
    0.3
    
    
    0.3
    
    
    0.3
    
    
    0.3
    
    
    
    
    
    
    0.5Subject to
      Mandatory Redemption
    
    
    --
    
    
    --
    
    
    --
    
    
    1.0
    
    
    
    
    
    
    1.9Company-Obligated
      Mandatorily
      Redeemable
      Preferred Securities
    
    
    --
    
    
    --
    
    
    2.7
    
    
    2.7
    
    
    
    
    
    
    4.5Long-Term
      Debt
    
    
    28.1
    
    
    25.7
    
    
    26.2
    
    
    26.8
    
    
    
    
    
    
    39.9Total
      Capitalization
    
    
    100.0
    %
    
    100.0
    %
    
    100.0
    %
    
    100.0
    %
    
    
    
    
    
    100.0
    %**Distribution
      Kilowatt-Hour Deliveries (Millions):**Residential
    
    
    9,355
    
    
    9,104
    
    
    8,976
    
    
    1,428
    
    
    
    7,042
    
    
    8,087Commercial
    
    
    8,877
    
    
    8,620
    
    
    8,509
    
    
    1,330
    
    
    
    6,787
    
    
    7,706Industrial
    
    
    3,070
    
    
    3,046
    
    
    3,171
    
    
    474
    
    
    
    2,670
    
    
    3,307Other
    
    
    73
    
    
    89
    
    
    81
    
    
    17
    
    
    
    66
    
    
    82Total
    
    
    21,375
    
    
    20,859
    
    
    20,737
    
    
    3,249
    
    
    
    16,565
    
    
    19,182**Customers
      Served:**Residential
    
    
    941,917
    
    
    931,227
    
    
    921,716
    
    
    909,494
    
    
    
    
    
    
    896,629Commercial
    
    
    115,861
    
    
    114,270
    
    
    112,385
    
    
    109,985
    
    
    
    
    
    
    107,479Industrial
    
    
    2,666
    
    
    2,705
    
    
    2,759
    
    
    2,785
    
    
    
    
    
    
    2,835Other
    
    
    1,320
    
    
    1,345
    
    
    1,393
    
    
    1,484
    
    
    
    
    
    
    1,551Total
    
    
    1,061,764
    
    
    1,049,547
    
    
    1,038,253
    
    
    1,023,748
    
    
    
    
    
    
    1,008,494



















3





**JERSEY
CENTRAL POWER & LIGHT COMPANY**








**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,
including by the Securities and Exchange Commission as disclosed in our
Securities and Exchange Commission filings, the availability and cost of
capital, our ability 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 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.*





**Reclassifications**





As discussed in
Note 1 to the consolidated financial statements, 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. These reclassifications did not change previously
reported results in 2003 and 2002.





**Results of
Operations**





Earnings on common
stock increased to $111 million from $68 million in 2003 principally due to the
absence of non-cash charges aggregating $185 million ($109 million after tax)
from a 2003 rate case decision disallowing recovery of certain regulatory assets
(see Regulatory Matters) and reduced purchased power costs in 2004 which were
partially offset by a decline in operating revenues. In 2003, earnings on common
stock decreased to $68 million, from $253 million in 2002, as a result of the
disallowed costs from the 2003 rate case decision. In addition, higher operating
revenues were more than offset by increases in purchased power and other
operating costs causing a decline in earnings.





Operating revenues
decreased $153 million or 6.5% in 2004 compared with 2003. The decrease in
revenues was due to a $107 million decline in distribution throughput revenues
and a $49 million decline in wholesale revenues partially offset by a $11
million increase in retail generation revenues. Our BGS obligation has been
transferred to external parties as a result of an NJBPU auction process that
extended the termination of our BGS obligation through July 2005 (see Note 7 -
Regulatory Matters). We had entered into long-term power purchase agreements in
connection with the divestiture of our generation facilities and had sold any
power in excess of our retail customer needs to the wholesale market. The
long-term purchase agreements ended after the first quarter of 2003 and as a
result, sales to the wholesale market subsequently decreased. Retail generation
sales revenues increased by $11 million in 2004 compared to 2003 due to higher
unit prices resulting from the BGS auction. This increase more than offset a
composite 13.2% decrease in kilowatt-hour sales (commercial - 16.0% and
industrial - 63.4%), which reflected increases in electric generation services
to commercial and industrial customers provided by alternative suppliers. The
shopping percentage in our franchise area increased 16.7 percentage points and
46.0 percentage points, for the commercial and industrial sectors respectively,
while the percentage of shopping by residential customers was relatively
unchanged.





The $107 million
decrease in distribution deliveries was due to lower unit prices that more than
offset the impact of the 2.5% volume increase in 2004 from the previous year.
The lower prices reflected the impact of the distribution rate decrease
effective August 1, 2003. Warmer temperatures in the summer and improving
economic conditions resulted, in large part, in higher residential, commercial
and industrial demand.





Operating revenues
increased $31 million in 2003 compared with 2002 due to an $87 million increase
in wholesale revenues offset by lower revenues from our distribution deliveries.
The wholesale revenues increase in 2003 reflected the impact of the BGS auction
discussed above.





4





Distribution
deliveries increased slightly in 2003 from the previous year. Lower unit prices
in 2003 more than offset the impact of the increased volume and reduced revenues
by $64 million. In addition, lower 2003 revenues reflected the impact of the
distribution rate decrease effective August 1, 2003. Colder temperatures
early in the year resulted in higher residential and commercial demand, which
was partially offset by a decrease in industrial demand.





Generation sales
revenues in 2003 compared to 2002 were lower by $24 million due to an 8.7%
decrease in kilowatt-hour sales. The decrease reflected a 9.1 percentage point
increase in customers choosing an alternate supplier in 2003 compared to 2002.
The reverse was true in 2002 where some customers who were receiving their power
from alternate suppliers returned to us as full service customers.





Changes in
kilowatt-hour sales by customer class in 2004 and 2003 are summarized in the
following table:








**Changes
      in Kilowatt-hour Sales**
    
    **2004**
    
    **2003*****Increase
      (Decrease)***Electric
      Generation:Retail
    
    
    (13.2
    )%
    
    (8.7
    )%Wholesale
    
    
    (19.1
    )%
    
    23.1
    %**Total
      Electric Generation Sales**
    
    
    **(14.7**
    **)%**
    
    **(2.4**
    **)%**Distribution
      Deliveries:Residential
    
    
    2.8
    %
    
    1.4
    %Commercial
    
    
    3.0
    %
    
    1.3
    %Industrial
    
    
    0.8
    %
    
    (3.9
    )%**Total
      Distribution Deliveries**
    
    
    **2.5**
    **%**
    
    **0.6**
    **%**








*Operating
Expenses and Taxes*





Total operating
expenses and taxes decreased $190 million in 2004, after increasing $220 million
in 2003, compared to the prior year. These increases include the non-cash
charges in 2003 for amounts disallowed by the NJBPU in its rate case decision
(see Regulatory Matters), of which $153 million was charged to purchased power
and $33 million was charged to amortization of regulatory assets. The following
table presents changes in 2004 and 2003 from the prior year by expense category.








**Operating
      Expenses and Taxes - Changes**
    
    **2004**
    
    **2003*****Increase
      (Decrease)***
    
    ***(In
      millions)***Fuel and
      purchased power costs
    
    $
    (220
    )
    $
    234Other
      operating costs
    
    
    (18
    )
    
    68Provision for
      depreciation
    
    
    (24
    )
    
    (23
    )Amortization
      of regulatory assets
    
    
    15
    
    
    73General
      taxes
    
    
    9
    
    
    (2
    )Income
      taxes
    
    
    48
    
    
    (130
    )**Total
      operating expenses and taxes**
    
    **$**
    **(190**
    **)**
    **$**
    **220**








Excluding the
disallowed deferred energy costs of $153 million in 2003, fuel and purchased
power decreased $67 million in 2004 compared to 2003. The lower purchased
power costs reflected lower kilowatt-hour purchases due to reduced generation
sales requirements as discussed above. Other operating expenses decreased $18
million in 2004 compared to 2003, due to cost containment efforts as
demonstrated by the 7% decline in the number of employees and the absence in
2004 of storm restoration costs incurred in the third quarter of
2003.





Depreciation
expense declined $24 million in 2004 and $23 million in 2003 compared to the
preceding year due to reduced depreciation rates effective August 1, 2003
in connection with the NJBPU rate case decision (see Regulatory Matters).
Amortization of regulatory assets, excluding $33 million of disallowed costs in
2003 from the rate decision discussed above, increased $48 million in 2004 and
$40 in 2003 due to increased regulatory asset recovery in connection with the
NJBPU rate case decision.








5





In 2003, excluding
the disallowed  deferred energy costs of $153 million, fuel and
purchased  power costs increased $81 million, compared to 2002. The
increase was due primarily to more power being purchased through two-party
agreements and changes to the deferred energy and capacity costs. Other
operating expenses increased $68 million in 2003 compared to 2002, due to higher
employee benefit costs, storm restoration expenses and costs associated with an
accelerated reliability plan within our service territory.





*Net Interest
Charges*





Net interest
charges decreased $6 million in 2004 and $5 million in 2003, compared to the
previous year, reflecting debt redemptions of $290 million and $252 million,
respectively. Those decreases were partially offset by interest on
$300 million of senior notes issued in April 2004 and $150 million of
senior notes issued in May 2003 which were used to redeem outstanding securities
in the second and third quarters of 2003.





*Preferred Stock
Dividend Requirements*





Preferred stock
dividend requirements were unchanged in 2004 and decreased $1.4 million in 2003,
compared to the prior year, due to the redemptions of cumulative preferred stock
pursuant to mandatory and optional sinking fund provisions. We realized non-cash
gains of $0.6 million in 2003 on the reacquisition of preferred stock.





**Capital
Resources and Liquidity**





Our cash
requirements in 2004 for operating expenses, construction expenditures and
scheduled debt maturities were met with a combination of cash from operations
and funds from the capital markets. During 2005 and thereafter, we expect to
meet our contractual obligations with cash from operations.





*Changes in Cash
Position*





As of
December 31, 2004, we had $0.2 million of cash and cash equivalents
compared with $0.3 million as of December 31, 2003. The major sources for
changes in these balances are summarized below.





*Cash Flows From
Operating Activities*





Our net cash
provided from operating activities was $263 million in 2004, $180 million in
2003 and $302 million in 2002, summarized as follows:








**Operating
      Cash Flows**
    
    **2004**
    
    **2003**
    
    **2002*****(In
      millions)***Cash earnings(1)
    
    $
    230
    
    $
    325
    
    $
    281Pension trust
      contribution
    
    
    (37
    )
    
    --
    
    
    --Working
      capital and other
    
    
    70
    
    
    (145
    )
    
    21Total
    
    $
    263
    
    $
    180
    
    $
    302





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


(2)  Pension trust
contribution net of $25 million of income tax benefits.





Cash earnings (in
the table above) are 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)
    
    $
    112
    
    $
    68
    
    $
    252Non-Cash
      Charges (Credits):Provision for
      depreciation
    
    
    75
    
    
    99
    
    
    121Amortization
      of regulatory assets
    
    
    279
    
    
    263
    
    
    190Revenue
      credits to customers
    
    
    --
    
    
    (72
    )
    
    (43
    )Disallowed
      regulatory assets
    
    
    --
    
    
    153
    
    
    --Deferred
      costs recoverable as regulatory assets
    
    
    (263
    )
    
    (276
    )
    
    (352
    )Deferred
      income taxes
    
    
    30
    
    
    62
    
    
    112Other
      non-cash expenses
    
    
    (3
    )
    
    28
    
    
    1Cash earnings
      (Non-GAAP)
    
    $
    230
    
    $
    325
    
    $
    281





6








Net 
cash  provided  from  operating  activities
 increased  by $83 million in 2004 and decreased by $121 million in
2003, as compared to the previous  year.  The increase in 2004 was due
to a $215 million increase in working capital which was partially offset by a
$95 million decrease in cash earnings as described under “Results of Operations” and a $37 million after-tax voluntary pension
trust contribution. The increase in working capital and other was attributable
to a $151 million increase in payables and a $53 million increase associated
with a NUG power contract restructuring. The decrease in 2003 was due to a $166
million increase in working capital and other requirements (primarily from a
$170 million reduction in payables) which was partially offset by a $44 million
increase in cash earnings.





*Cash Flows From
Financing Activities*





Net cash used for
financing activities was $82 million, $139 million and $140 million in 2004,
2003 and 2002, respectively. These amounts reflect redemptions of debt and
preferred stock, in addition to payments of $90 million in 2004, $138 million in
2003 and $191 million in 2002 for common stock dividends to FirstEnergy. The
following table provides details regarding new issues and redemptions during
each year:








**Securities
      Issued or Redeemed in**
    
    **2004**
    
    **2003**
    
    **2002*****(In
      millions)****New
      Issues*Secured
      Notes
    
    $
    300
    
    $
    150
    
    $
    --Transition
      Bonds (See Note 8(C))
    
    
    --
    
    
    --
    
    
    320*Redemptions*First
      Mortgage Bonds
    
    $
    290
    
    $
    150
    
    $
    192Medium Term
      Notes
    
    
    --
    
    
    102
    
    
    --Preferred
      Stock
    
    
    --
    
    
    125
    
    
    52Transition
      Bonds
    
    
    16
    
    
    --
    
    
    --Other
    
    
    3
    
    
    --
    
    
    4Total
      Redemptions
    
    $
    309
    
    $
    377
    
    $
    248*Short-term
      Borrowings, net*
    
    $
    18
    
    $
    231
    
    $
    (18
    )








We had $249 million
of short-term  indebtedness at the end of 2004, compared to $231 million of
short-term  debt at the end of 2003. The Company has obtained authorization
from the SEC to incur short-term debt up to its charter limit of $415 million
(including the utility money pool). We will not issue FMB other than as
collateral for senior notes, since our senior note indentures prohibit (subject
to certain exceptions) us from issuing any debt which is senior to the senior
notes. As of December 31, 2004, we had the capability to issue $644 million
of additional senior notes based upon FMB collateral. At year-end 2004, based
upon applicable earnings coverage tests and our charter, we could issue $583
million of preferred stock (assuming no additional debt was
issued).





We have the ability
to borrow from our regulated affiliates and FirstEnergy to meet our short-term
working capital requirements. FESC administers this money pool and tracks
surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving
a loan under the money pool agreements must repay the principal, together with
accrued interest, within 364 days of borrowing the funds. The rate of interest
is the same for each company receiving a loan from the pool and is based on the
average cost of funds available through the pool. The average interest rate for
borrowings under these arrangements in 2004 was 1.43%.





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








**Ratings
      of Securities****Securities**
    **S&P**
    **Moody’s**
    **Fitch****FirstEnergy**
    Senior
      unsecured
    BB+
    Baa3
    BBB-**JCP&L**
    Senior
      secured
    BBB+
    Baa1
    BBB+Preferred
      stock
    BB
    Ba1
    BBB











7





On December 10,
2004, S&P reaffirmed FirstEnergy's ‘BBB-' corporate credit rating and kept
the outlook stable. S&P noted that the stable outlook reflects FirstEnergy's
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, FirstEnergy's 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*





Cash used in
investing activities increased $136 million in 2004 and decreased $143 million
in 2003. The increase in 2004 resulted primarily from a $56 million increase in
property additions and a $79 million decrease in loan repayments from associated
companies. The 2003 change was principally due to a $155 million increase in
loan repayments from associated companies.





Our capital
spending for the period 2005-2007 is expected to be approximately $511 million
for property additions and improvements, of which approximately $178 million
applies to 2005.





**Contractual
Obligations**





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





**Contractual
      Obligations**
    
    **Total**
    
    **2005**
    
    **2006-**
      **2007**
    
    **2008-**
      **2009**
    
    **Thereafter*****(In
      millions)***Long-term
      debt (2)
    
    $
    1,264
    
    $
    17
    
    $
    226
    
    $
    44
    
    $
    977Short-term
      borrowings
    
    
    249
    
    
    249
    
    
    --
    
    
    --
    
    
    --Operating
      leases
    
    
    62
    
    
    2
    
    
    3
    
    
    4
    
    
    53Purchases(1)
    
    
    3,374
    
    
    568
    
    
    1,068
    
    
    837
    
    
    901Total
    
    $
    4,949
    
    $
    836
    
    $
    1,297
    
    $
    885
    
    $
    1,931





(1) 
Power purchases under contracts with fixed or minimum quantities and approximate
timing.


(2) 
Amounts reflected do not include interest on long-term debt.





**Market Risk
Information**





We use various
market risk sensitive instruments, including derivative contracts, primarily to
manage the risk of price fluctuations. Our Risk Policy Committee, comprised of
members of senior management, provides general management oversight to risk
management activities throughout our 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 and natural gas prices.
To manage the volatility relating to these exposures, we use a variety of
non-derivative and derivative instruments, including forward contracts, options
and futures contracts. The derivatives are used for hedging 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:








8





**Increase
(Decrease) in the Fair Value of Commodity Derivative
Contracts**





**Non-Hedge**
    
    **Hedge**
    
    **Total*****(In
      millions)*****Change
      in the Fair Value of Commodity Derivative
    Contracts**Outstanding
      net asset as of January 1, 2004
    
    $
    16
    
    $
    --
    
    $
    16New contract
      value when entered
    
    
    --
    
    
    --
    
    
    --Additions/Change
      in value of existing contracts
    
    
    (1
    )
    
    --
    
    
    (1
    )Change in
      techniques/assumptions
    
    
    --
    
    
    --
    
    
    --Settled
      contracts
    
    
    --
    
    
    --
    
    
    --**Net
      Assets - Derivatives Contracts as of**
      **December
      31, 2004** (1)
    
    **$**
    **15**
    
    **$**
    **--**
    
    **$**
    **15****Income
      Statement Impact of Changes in Commodity Derivative Contracts****(2)**
    
    
    (1
    )
    $
    --
    
    $
    (1
    )




(1) Includes
$15 million in non-hedge commodity derivative contracts which are offset by a
regulatory liability.


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





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








**Non-Hedge**
    
    **Hedge**
    
    **Total*****(In
      millions)*****Non-Current--**Other
      Deferred Charges
    
    $
    15
    
    $
    --
    
    $
    15**Net
      assets**
    
    **$**
    **15**
    
    **$**
    **--**
    
    **$**
    **15**








The valuation of
derivative contracts is based on observable market information to the extent
that such information is available. In cases where such information is not
available, 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 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)***Other
      external sources (1)
    
    $
    4
    
    $
    3
    
    $
    --
    
    $
    --
    
    $
    --
    
    $
    7Prices based
      on models
    
    
    --
    
    
    --
    
    
    2
    
    
    2
    
    
    4
    
    
    8**Total**(2)
    
    **$******
    ******4**
    
    **$******
    ******3**
    
    **$******
    ******2**
    
    **$******
    ******2**
    
    **$******
    ******4**
    
    **$******
    ******15**





(1) Broker
quote sheets.


(2) Includes
$15 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 position. A hypothetical 10% adverse shift in quoted market prices in
the near term on derivative instruments would not have had a material effect on
our consolidated financial position or cash flows as of December 31,
2004.





Interest
Rate Risk





Our exposure to
fluctuations in market interest rates is reduced since our debt has fixed
interest rates, as noted in the following table.











9





**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 Cash
      Equivalents-Fixed
      Income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    218
    
    **$**
    **218**
    
    **$**
    **218**Average
      interest rate
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    4.6
    %
    
    4.6
    %LiabilitiesLong-term
      Debt and Other
      Long-Term
      Obligations:Fixed
      rate
    
    $
    17
    
    $
    208
    
    $
    18
    
    $
    19
    
    $
    25
    
    $
    977
    
    **$**
    **1,264**
    
    **$**
    **1,252**Average
      interest rate
    
    
    4.2
    %
    
    6.3
    %
    
    4.2
    %
    
    5.4
    %
    
    5.7
    %
    
    6.1
    %
    
    6.1
    %Short-term
      Borrowings
    
    
    249
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    **$**
    **249**
    
    **$**
    **249**Average
      interest rate
    
    
    2.0
    %
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2.0
    %








**Equity
Price Risk**





Included in nuclear
decommissioning trusts are marketable equity securities carried at their current
fair value of approximately $80 million and $69 million at December 31,
2004 and 2003, respectively. A hypothetical 10% decrease in prices quoted by
stock exchanges would result in a $8 million reduction in fair value as of
December 31, 2004. (See Note 4 Fair Value of Financial
Instruments)





**Outlook**





Beginning in 1999,
all of our customers were able to select alternative energy suppliers. We
continue to deliver power to homes and businesses through our existing
distribution system, which remains regulated. To support customer choice, rates
were restructured into unbundled service charges and additional non-bypassable
charges to recover stranded costs.





Regulatory assets
are costs which have been authorized by the NJBPU and the FERC 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 when incurred. All of our regulatory assets
are expected to continue to be recovered under the provisions of the regulatory
proceedings discussed below. Our regulatory assets totaled $2.2 billion and $2.6
billion as of December 31, 2004 and December 31, 2003, respectively.





*Regulatory
Matters*





In July 2003, the
NJBPU announced our base electric rate proceeding decision, which reduced our
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 our rate base. The decision ordered that a Phase II proceeding
be conducted to review whether we are in compliance with current service
reliability and quality standards. The NJBPU also ordered that any expenditures
and projects undertaken by us to increase our system's reliability 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 our
return on equity to 9.75% or decrease it to 9.25%, depending on its assessment
of the reliability of our service. Any reduction would be retroactive to
August 1, 2003. We 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. We 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.








10





On July 16,
2004, we 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.





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 the
findings of a Special Reliability Master (SRM) report and an operations
audit.





*Employee
Matters*





On December 8,
2004, employees represented by IBEW System Council U-3 began a strike against
the Company. The Company continues to utilize management, other non-union
personnel from around FirstEnergy’s system and contractors to perform service
reliability and priority maintenance work while the union members are on strike.
The labor agreement between the Company and System Council U-3 originally
expired on October 31, 2003 but was extended several times and ultimately
expired on December 7, 2004. The Company and the leadership of System
Council U-3 continue to negotiate in an attempt to reach a new agreement and end
the work stoppage. It is unknown when such an agreement will be reached or when
the work stoppage will end.





Environmental
Matters





We have been named
as a PRP at waste disposal sites which may require cleanup under the
Comprehensive Environmental Response, Compensation and Liability Act of 1980.
Allegations of disposal of hazardous substances at historical sites and the
liability involved are often unsubstantiated and subject to dispute; however,
federal law provides that all PRPs for a particular site be held liable on a
joint and several basis. Therefore, environmental liabilities that are
considered probable have been recognized on the Consolidated Balance Sheet as of
December 31, 2004, based on estimates of the total costs of cleanup, our
proportionate responsibility for such costs and the financial ability of other
nonaffiliated entities to pay. We have accrued liabilities aggregating
approximately $47 million as of December 31, 2004, which are being
recovered through a non-bypassable SBC. We do not believe environmental
remediation costs will have a material adverse effect on our financial
condition, cash flows or results of operations.





*Power Outages
and Related Litigation*





In July 1999, the
Mid-Atlantic states experienced a severe heat storm which resulted in power
outages throughout the service territories of many electric utilities, including
our 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, we provided unsafe, inadequate or improper service
to our customers. Two class action lawsuits (subsequently consolidated into a
single proceeding) were filed in New Jersey Superior Court in July 1999 against
us, GPU and other GPU companies, seeking compensatory and punitive damages
arising from the July 1999 service interruptions in the our territory.





In August 2002, the
trial court granted partial summary judgment to us and dismissed the plaintiffs'
claims for consumer fraud, common law fraud, negligent misrepresentation, and
strict product liability. In November 2003, the trial court granted our 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 us for leave to
appeal the decision of the Appellate Court. We are unable to predict the outcome
of these matters and no liability has been accrued as of December 31,
2004.








11





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





Legal
Matters





Various 
lawsuits, claims  (including claims for asbestos  exposure) and
proceedings  related to our normal  business operations are pending
against us, the most significant of which are described above.





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*





We are 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.





*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.








12





*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 the 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, FirstEnergy made a $500 million voluntary contribution to its
pension plan (our share was $62 million). 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. FirstEnergy's 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 $46 million. As
prescribed by SFAS 87, we increased our additional minimum liability by $9
million, offset by a charge to OCI. The balance in AOCL of $53 million (net of
$37 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.





*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.








13





*Nuclear
Decommissioning*





In accordance with
SFAS 143, we recognize an ARO for the future decommissioning of TMI-2. 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 plant's 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.
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.










14





**JERSEY
CENTRAL POWER & LIGHT COMPANY**





**CONSOLIDATED
STATEMENTS OF INCOME**














**2004**
    
    **2003**
    
    **2002*****(In
      thousands)*****OPERATING
      REVENUES (Note 2(H))**
    $
    2,206,987
    
    $
    2,359,646
    
    $
    2,328,415**OPERATING
      EXPENSES AND TAXES:**Fuel and
      purchased power (Note 2(H))
    
    1,166,430
    
    
    1,386,899
    
    
    1,153,415Other
      operating costs (Note 2(H))
    
    350,709
    
    
    368,714
    
    
    300,602Provision for
      depreciation
    
    75,163
    
    
    98,711
    
    
    121,444Amortization
      of regulatory assets
    
    278,559
    
    
    263,227
    
    
    190,200General
      taxes
    
    62,792
    
    
    53,481
    
    
    56,049Income
      taxes
    
    89,425
    
    
    41,839
    
    
    171,496Total
      operating expenses and taxes
    
    2,023,078
    
    
    2,212,871
    
    
    1,993,206**OPERATING
      INCOME**
    
    183,909
    
    
    146,775
    
    
    335,209**OTHER
      INCOME**
    
    7,761
    
    
    7,026
    
    
    7,653**NET
      INTEREST CHARGES:**Interest on
      long-term debt
    
    80,840
    
    
    87,681
    
    
    92,314Allowance for
      borrowed funds used duringconstruction
    
    (615
    )
    
    (296
    )
    
    (583
    )Deferred
      interest
    
    (3,545
    )
    
    (8,639
    )
    
    (8,815
    )Other
      interest expense
    
    3,351
    
    
    1,691
    
    
    (2,643
    )Subsidiary’s
      preferred stock dividend requirements
    
    --
    
    
    5,347
    
    
    10,694Net interest
      charges
    
    80,031
    
    
    85,784
    
    
    90,967**NET
      INCOME**
    
    111,639
    
    
    68,017
    
    
    251,895**PREFERRED
      STOCK DIVIDEND REQUIREMENTS**
    
    500
    
    
    500
    
    
    2,125**GAIN
      ON PREFERRED STOCK REACQUISITION**
    
    --
    
    
    (612
    )
    
    (3,589
    )**EARNINGS
      ON COMMON STOCK**
    $
    111,139
    
    $
    68,129
    
    $
    253,359














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








15





**JERSEY
CENTRAL POWER & LIGHT COMPANY**





**CONSOLIDATED
BALANCE SHEETS**


**As of
      December 31,**
    **2004**
    
    **2003*****(In
      thousands)*****ASSETS****UTILITY
      PLANT:**In
      service
    $
    3,730,767
    
    $
    3,642,467Less-Accumulated
      provision for depreciation
    
    1,380,775
    
    
    1,367,0422,349,992
    
    
    2,275,425Construction
      work in progress
    
    75,012
    
    
    48,9852,425,004
    
    
    2,324,410**OTHER
      PROPERTY AND INVESTMENTS:**Nuclear plant
      decommissioning trusts
    
    138,205
    
    
    125,945Nuclear fuel
      disposal trust
    
    159,696
    
    
    155,774Long-term
      notes receivable from associated companies
    
    20,436
    
    
    19,579Other
    
    19,379
    
    
    18,744337,716
    
    
    320,042**CURRENT
      ASSETS:**Cash and cash
      equivalents
    
    162
    
    
    271Receivables-Customers
      (less accumulated provisions of $3,881,000 and $4,296,000respectively,
      for uncollectible accounts)
    
    201,415
    
    
    198,061Associated
      companies
    
    86,531
    
    
    70,012Other (less
      accumulated provisions of $162,000 and $1,183,000
      respectively)
    
    39,898
    
    
    46,411Materials and
      supplies, at average cost
    
    2,435
    
    
    2,480Prepayments
      and other
    
    31,489
    
    
    49,360361,930
    
    
    366,595**DEFERRED
      CHARGES:**Regulatory
      assets
    
    2,176,520
    
    
    2,558,214Goodwill
    
    1,985,036
    
    
    2,001,302Other
    
    4,978
    
    
    8,4814,166,534
    
    
    4,567,997$
    7,291,184
    
    $
    7,579,044**CAPITALIZATION
      AND LIABILITIES****CAPITALIZATION**(See
      Consolidated Statements of Capitalization):Common
      stockholder’s equity
    $
    3,155,362
    
    $
    3,153,974Preferred
      stock not subject to mandatory redemption
    
    12,649
    
    
    12,649Long-term
      debt
    
    1,238,984
    
    
    1,095,9914,406,995
    
    
    4,262,614**CURRENT
      LIABILITIES:**Currently
      payable long-term debt
    
    16,866
    
    
    175,921Notes payable
      (Note 10)-Associated
      companies
    
    248,532
    
    
    230,985Accounts
      payable-Associated
      companies
    
    20,605
    
    
    42,410Other
    
    124,733
    
    
    105,815Accrued
      taxes
    
    2,626
    
    
    919Accrued
      interest
    
    10,359
    
    
    14,843Other
    
    65,130
    
    
    58,094488,851
    
    
    628,987**NONCURRENT
      LIABILITIES:**Power
      purchase contract loss liability
    
    1,268,478
    
    
    1,473,070Accumulated
      deferred income taxes
    
    645,741
    
    
    640,208Nuclear fuel
      disposal costs
    
    169,884
    
    
    167,936Asset
      retirement obligation
    
    72,655
    
    
    109,851Retirement
      benefits
    
    103,036
    
    
    159,219Other
    
    135,544
    
    
    137,1592,395,338
    
    
    2,687,443**COMMITMENTS
      AND CONTINGENCIES**(Notes 5 and
      11).$
    7,291,184
    
    $
    7,579,044








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





16





**JERSEY
CENTRAL POWER & LIGHT COMPANY**





**CONSOLIDATED
STATEMENTS OF CAPITALIZATION**





**As of
      December 31,**
    
    **2004**
    
    **2003*****(Dollars
      in thousands, except per share amounts)*****COMMON
      STOCKHOLDER'S EQUITY:**Common stock,
      par value $10 per share, authorized 16,000,000 shares15,371,270
      shares outstanding
    
    $
    153,713
    
    $
    153,713Other paid-in
      capital
    
    
    3,013,912
    
    
    3,029,894Accumulated
      other comprehensive loss (Note 2(F))
    
    
    (55,534
    )
    
    (51,765
    )Retained
      earnings (Note 8(A))
    
    
    43,271
    
    
    22,132Total common
      stockholder's equity
    
    
    3,155,362
    
    
    3,153,974





**Number
      of Shares**
      **Outstanding**
    
    **Optional**
      **Redemption
      Price****2004**
    
    **2003**
    
    **Per
      Share**
    
    **Aggregate****PREFERRED
      STOCK NOT SUBJECT TO****MANDATORY
      REDEMPTION (Note 8(B)):**Cumulative,
      without par value-Authorized
      125,000 shares4.00%
      Series
    
    
    125,000
    
    
    125,000
    
    $
    106.50
    
    $
    13,313
    
    
    12,649
    
    
    12,649**LONG-TERM
      DEBT (Note 8(C)):**First
      mortgage bonds:7.125% due
      2004
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    --
    
    
    160,0006.780% due
      2005
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    --
    
    
    50,0006.850% due
      2006
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    40,000
    
    
    40,0007.125% due
      2009
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    5,985
    
    
    6,3007.100% due
      2015
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    12,200
    
    
    12,2008.320% due
      2022
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    --
    
    
    40,0007.980% due
      2023
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    --
    
    
    40,0007.500% due
      2023
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    125,000
    
    
    125,0008.450% due
      2025
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    50,000
    
    
    50,0006.750% due
      2025
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    150,000
    
    
    150,000Total first
      mortgage bonds
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    383,185
    
    
    673,500Secured
      notes:6.450% due
      2006
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    150,000
    
    
    150,0004.190% due
      2007
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    51,723
    
    
    67,3125.390% due
      2010
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    52,297
    
    
    52,2975.810% due
      2013
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    77,075
    
    
    77,0755.625% due
      2016
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    300,000
    
    
    --6.160% due
      2017
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    99,517
    
    
    99,5174.800% due
      2018
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    150,000
    
    
    150,000Total secured
      notes
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    880,612
    
    
    596,201Unsecured
      notes:7.69% due
      2039
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    --
    
    
    2,968Net
      unamortized discount on debt
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (7,947
    )
    
    (757
    )Long-term
      debt due within one year
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (16,866
    )
    
    (175,921
    )Total
      long-term debt
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,238,984
    
    
    1,095,991**TOTAL
      CAPITALIZATION**
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    4,406,995
    
    $
    4,262,614








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







17








**JERSEY
CENTRAL POWER & LIGHT COMPANY**





**CONSOLIDATED
STATEMENTS OF COMMON STOCKHOLDER’S EQUITY**





AccumulatedCommon
      Stock
    
    Other
    
    OtherComprehensive
    
    Number
    
    Par
    
    Paid-In
    
    Comprehensive
    
    RetainedIncome
    
    of
      Shares
    
    Value
    
    Capital
    
    Income
      (Loss)
    
    Earnings*(Dollars
      in thousands)*Balance,
      January 1, 2002
    
    
    
    
    
    15,371,270
    
    $
    153,713
    
    $
    2,981,117
    
    $
    (472
    )
    $
    29,343Net
      income
    
    $
    251,895
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    251,895Net
      unrealized loss on derivative instruments
    
    
    (393
    )
    
    
    
    
    
    
    
    
    
    
    (393
    )Comprehensive
      income
    
    $
    251,502Cash
      dividends on preferred stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,465Cash
      dividends on common stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (190,700
    )Purchase
      accounting fair value adjustment
    
    
    
    
    
    
    
    
    
    
    
    48,101Balance,
      December 31, 2002
    
    
    
    
    
    15,371,270
    
    
    153,713
    
    
    3,029,218
    
    
    (865
    )
    
    92,003Net
      income
    
    $
    68,017
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    68,017Net
      unrealized loss on derivative instruments
    
    
    (3,020
    )
    
    
    
    
    
    
    
    
    
    
    (3,020
    )Minimum
      liability for unfunded retirement
      benefits, net
      of $(32,998,000) of income taxes(47,880
    )
    
    
    
    
    
    
    
    
    
    
    (47,880
    )Comprehensive
      income
    
    $
    17,117Cash
      dividends on preferred stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (500
    )Cash
      dividends on common stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (138,000
    )Gain on
      preferred stock reacquisition
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    612Purchase
      accounting fair value adjustment
    
    
    
    
    
    
    
    
    
    
    
    676Balance,
      December 31, 2003
    
    
    
    
    
    15,371,270
    
    
    153,713
    
    
    3,029,894
    
    
    (51,765
    )
    
    22,132Net
      income
    
    $
    111,639
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    111,639Net
      unrealized loss on investments
    
    
    (5
    )
    
    
    
    
    
    
    
    
    
    
    (5
    )Net
      unrealized gain on derivative instruments,net of
      $1,583,000 of income taxes
    
    
    1,697
    
    
    
    
    
    
    
    
    
    
    
    1,697Minimum
      liability for unfunded retirement
      benefits, net
      of $(3,772,000) of income taxes(5,461
    )
    
    
    
    
    
    
    
    
    
    
    (5,461
    )Comprehensive
      income
    
    $
    107,870Cash
      dividends on preferred stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (500
    )Cash
      dividends on common stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (90,000
    )Purchase
      accounting fair value adjustment
    
    
    
    
    
    
    
    
    
    
    
    (15,982
    )Balance,
      December 31, 2004
    
    
    
    
    
    15,371,270
    
    $
    153,713
    
    $
    3,013,912
    
    $
    (55,534
    )
    $
    43,271

















**CONSOLIDATED
STATEMENTS OF PREFERRED STOCK**





**Not
      Subject to**
    
    **Subject
      to****Mandatory
      Redemption**
    
    **Mandatory
      Redemption****Number**
    
    **Carrying**
    
    **Number**
    
    **Carrying****of
      Shares**
    
    **Value**
    
    **of
      Shares**
    
    **Value*****(Dollars
      in thousands)***Balance,
      January 1, 2002
    
    125,000
    
    $
    12,649
    
    
    5,515,001
    
    $
    180,951Redemptions-7.52%
      Series
    
    
    
    
    
    
    
    (265,000
    )
    
    (28,951
    )8.65%
      Series
    
    
    
    
    
    
    
    (250,001
    )
    
    (26,750
    )Amortization
      of fair marketValue
      adjustment
    
    
    
    
    
    
    
    
    
    
    (6
    )Balance,
      December 31, 2002
    
    125,000
    
    
    12,649
    
    
    5,000,000
    
    $
    125,244Redemptions-8.56%
      Series
    
    
    
    
    
    
    
    (5,000,000
    )
    
    (125,242
    )Amortization
      of fair marketvalue
      adjustment
    
    
    
    
    
    
    
    
    
    
    (2
    )Balance,
      December 31, 2003
    
    125,000
    
    
    12,649
    
    
    --
    
    
    --Balance,
      December 31, 2004
    
    125,000
    
    $
    12,649
    
    
    --
    
    $
    --








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










18





**JERSEY
CENTRAL POWER & LIGHT COMPANY**





**CONSOLIDATED
STATEMENTS OF CASH FLOWS**





**2004**
    
    **2003**
    
    **2002*****(In
      thousands)*****CASH
      FLOWS FROM OPERATING ACTIVITIES:**Net
      Income
    
    $
    111,639
    
    $
    68,017
    
    $
    251,895Adjustments
      to reconcile net income to netcash from
      operating activities:Provision for
      depreciation
    
    
    75,163
    
    
    98,711
    
    
    121,444Amortization
      of regulatory assets
    
    
    278,559
    
    
    263,227
    
    
    190,200Deferred
      costs, net
    
    
    (263,257
    )
    
    (276,214
    )
    
    (351,950
    )Deferred
      income taxes and investment tax credits, net
    
    
    54,887
    
    
    62,372
    
    
    112,315NUG power
      contract restructuring
    
    
    52,800
    
    
    --
    
    
    --Pension trust
      contribution
    
    
    (62,499
    )
    
    --
    
    
    --Revenue
      credits to customers
    
    
    --
    
    
    (71,984
    )
    
    (43,016
    )Disallowed
      regulatory assets
    
    
    --
    
    
    152,500
    
    
    --Accrued
      retirement benefit obligation
    
    
    (2,986
    )
    
    8,381
    
    
    --Accrued
      compensation, net
    
    
    1,014
    
    
    19,864
    
    
    (59
    )Receivables
    
    
    (13,360
    )
    
    4,528
    
    
    (14,542
    )Materials and
      supplies
    
    
    45
    
    
    (1,139
    )
    
    7Accounts
      payable
    
    
    (2,887
    )
    
    (153,953
    )
    
    16,399Other
    
    
    33,535
    
    
    5,642
    
    
    19,597Net cash
      provided from operating activities
    
    
    262,653
    
    
    179,952
    
    
    302,290**CASH
      FLOWS FROM FINANCING ACTIVITIES:**New
      Financing-Long-term
      debt
    
    
    300,000
    
    
    150,000
    
    
    318,106Short-term
      borrowings, net
    
    
    17,547
    
    
    230,985
    
    
    --Redemptions
      and Repayments-Preferred
      stock
    
    
    --
    
    
    (125,244
    )
    
    (51,500
    )Long-term
      debt
    
    
    (308,872
    )
    
    (251,815
    )
    
    (196,033
    )Short-term
      borrowings, net
    
    
    --
    
    
    --
    
    
    (18,149
    )Dividend
      Payments-Common
      stock
    
    
    (90,000
    )
    
    (138,000
    )
    
    (190,700
    )Preferred
      stock
    
    
    (500
    )
    
    (5,235
    )
    
    (2,125
    )Net cash used
      for financing activities
    
    
    (81,825
    )
    
    (139,309
    )
    
    (140,401
    )**CASH
      FLOWS FROM INVESTING ACTIVITIES:**Property
      additions
    
    
    (178,877
    )
    
    (122,930
    )
    
    (97,346
    )Contributions
      to decommissioning trusts
    
    
    (2,895
    )
    
    (2,630
    )
    
    --Loan
      repayments from (payments to) associated companies, net
    
    
    (857
    )
    
    78,112
    
    
    (77,358
    )Other
    
    
    1,692
    
    
    2,253
    
    
    (13,786
    )Net cash used
      for investing activities
    
    
    (180,937
    )
    
    (45,195
    )
    
    (188,490
    )Net increase
      (decrease) in cash and cash equivalents
    
    
    (109
    )
    
    (4,552
    )
    
    (26,601
    )Cash and cash
      equivalents at beginning of period
    
    
    271
    
    
    4,823
    
    
    31,424Cash and cash
      equivalents at end of period
    
    $
    162
    
    $
    271
    
    $
    4,823**SUPPLEMENTAL
      CASH FLOWS INFORMATION:**Cash Paid
      During the Year-Interest (net
      of amounts capitalized)
    
    $
    83,341
    
    $
    101,432
    
    $
    92,152Income
      taxes
    
    $
    58,549
    
    $
    16,883
    
    $
    83,776











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










19











**JERSEY
CENTRAL POWER & LIGHT COMPANY**





**CONSOLIDATED
STATEMENTS OF TAXES**








**2004**
    
    **2003**
    
    **2002*****(In
      thousands)*****GENERAL
      TAXES:**New Jersey
      Transitional Energy Facilities Assessment*
    $
    49,455
    
    $
    38,668
    
    $
    39,387Real and
      personal property
    
    4,894
    
    
    3,889
    
    
    4,362Social
      security and unemployment
    
    8,287
    
    
    4,826
    
    
    --Other
    
    156
    
    
    6,098
    
    
    12,300Total general
      taxes
    $
    62,792
    
    $
    53,481
    
    $
    56,049**PROVISION
      FOR INCOME TAXES:**Currently
      payable (receivable)-Federal
    $
    29,862
    
    $
    (15,687
    )
    $
    55,731State
    
    10,363
    
    
    (245
    )
    
    13,80940,225
    
    
    (15,932
    )
    
    69,540Deferred,
      net-Federal
    
    50,817
    
    
    54,252
    
    
    88,758State
    
    5,657
    
    
    10,348
    
    
    27,10856,474
    
    
    64,600
    
    
    115,866Investment
      tax credit amortization
    
    (1,587
    )
    
    (2,228
    )
    
    (3,551
    )Total
      provision for income taxes
    $
    95,112
    
    $
    46,440
    
    $
    181,855**INCOME
      STATEMENT CLASSIFICATION****OF
      PROVISION FOR INCOME TAXES:**Operating
      income
    $
    89,425
    
    $
    41,839
    
    $
    171,496Other
      income
    
    5,687
    
    
    4,601
    
    
    10,359Total
      provision for income taxes
    $
    95,112
    
    $
    46,440
    
    $
    181,855**RECONCILIATION
      OF FEDERAL INCOME TAX****EXPENSE
      AT STATUTORY RATE TO TOTAL****PROVISION
      FOR INCOME TAXES:**Book income
      before provision for income taxes
    $
    206,751
    
    $
    114,457
    
    $
    433,749Federal
      income tax expense at statutory rate
    $
    72,363
    
    $
    40,060
    
    $
    151,812Increases
      (reductions) in taxes resulting from-Amortization
      of investment tax credits
    
    (1,587
    )
    
    (2,228
    )
    
    (3,551
    )Depreciation
    
    4,485
    
    
    3,315
    
    
    7,154State income
      tax, net of federal benefit
    
    10,413
    
    
    7,178
    
    
    27,111Other,
      net
    
    9,438
    
    
    (1,885
    )
    
    (671
    )Total
      provision for income taxes
    $
    95,112
    
    $
    46,440
    
    $
    181,855**ACCUMULATED
      DEFERRED INCOME TAXES AT****DECEMBER
      31:**Property
      basis differences
    $
    386,071
    
    $
    371,811
    
    $
    297,983Nuclear
      decommissioning
    
    27,123
    
    
    34,663
    
    
    44,775Deferred sale
      and leaseback costs
    
    (17,836
    )
    
    (16,651
    )
    
    (16,451
    )Purchase
      accounting basis difference
    
    (1,253
    )
    
    (1,253
    )
    
    (1,253
    )Sale of
      generation assets
    
    (15,614
    )
    
    (17,861
    )
    
    (17,861
    )Regulatory
      transition charge
    
    213,665
    
    
    197,729
    
    
    224,117Provision for
      rate refund
    
    --
    
    
    --
    
    
    (29,370
    )Customer
      receivables for future income taxes
    
    (27,239
    )
    
    (4,519
    )
    
    (5,336
    )Oyster Creek
      securitization
    
    184,245
    
    
    193,558
    
    
    202,448Other
      comprehensive income
    
    (38,353
    )
    
    (32,998
    )
    
    --Employee
      benefits
    
    1,652
    
    
    (29,129
    )
    
    --Other
    
    (66,720
    )
    
    (55,142
    )
    
    (7,331
    )Net deferred
      income tax liability
    $
    645,741
    
    $
    640,208
    
    $
    691,721





* 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.













20





**NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS**





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





The
consolidated  financial  statements include JCP&L (Company)
and its wholly owned subsidiaries. The Company is a wholly owned subsidiary of
FirstEnergy. FirstEnergy also holds directly all of the issued and outstanding
common shares of its other principal electric utility operating subsidiaries,
including OE, CEI, TE, ATSI, Met-Ed and Penelec.





The Company follows
GAAP and complies with the regulations, orders, policies and practices
prescribed by the SEC, NJBPU and the FERC. 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. Expenses
(including transmission and congestion charges) were reclassified among
purchased power, other operating costs and amortization of regulatory assets to
conform with the current year presentation of generation commodity
costs.





The Company
consolidates all majority-owned subsidiaries, over which the Company exercises
control and, when applicable, entities for which the Company has a controlling
financial interest and VIEs for which the Company or any of its subsidiaries is
the primary beneficiary. Intercompany transactions and balances are eliminated
in consolidation. Investments in nonconsolidated affiliates (20-50 percent owned
companies, joint ventures and partnerships) over which 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. These reclassifications did not change
previously reported results in 2003 and 2002.





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**





The Company
accounts for the effects of regulation through the application of SFAS 71 to its
operating utilities when its 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.





*Regulatory
Assets-*





The Company
recognizes, as regulatory assets, costs which the FERC and the 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 Company’s regulatory plan. The Company continues to bill and collect
cost-based rates for its transmission and distribution services, which remain
regulated; accordingly, it is appropriate that the Company continue the
application of SFAS 71 to those operations.





21





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





**2004**
    
    **2003*****(In
      millions)***Regulatory
      transition charge
    
    $
    2,215
    
    $
    2,457Societal
      benefits charge
    
    
    51
    
    
    82Property
      losses and unrecovered plant costs
    
    
    50
    
    
    70Liabilities
      to customers - income taxes
    
    
    (58
    )
    
    --Employee
      postretirement benefit costs
    
    
    27
    
    
    30Loss on
      reacquired debt
    
    
    18
    
    
    15Spent fuel
      disposal costs
    
    
    (1
    )
    
    3Component
      removal costs
    
    
    (150
    )
    
    (150
    )Other
    
    
    25
    
    
    51Total
    
    $
    2,177
    
    $
    2,558








Regulatory
transition charges as of December 31, 2004 include $1.2 billion for the deferral
of above-market costs from power supplied by NUGs. These costs are being
recovered through BGS and MTC revenues.





Accounting for
Generation Operations-





The application of
SFAS 71 was discontinued in 1999 with respect to the Company’s  generation
operations.  The Company  subsequently divested substantially all
of its generating assets. The SEC's interpretive guidance and EITF 97-4
regarding asset impairment measurement, provides 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. Net assets included in utility plant
relating to operations for which the application of SFAS 71 was
discontinued were $39 million as of December 31, 2004.





**(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 Company’s
principal business is providing electric service to customers in New Jersey. The
Company’s 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 Company accrues the estimated unbilled
amount receivable as revenue and reverses the related prior period
estimate.





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
the Company's customers. Total customer receivables were $201 million (billed -
$122 million and unbilled - $79 million) and $198 million (billed - $119 million
and unbilled - $79 million) as of December 31, 2004 and 2003,
respectively.





**(D)**
    **PROPERTY,
      PLANT AND EQUIPMENT-**





As a result of the
Company's acquisition by FirstEnergy, a portion of the Company’s property, plant
and equipment was adjusted to reflect fair value. The majority of the Company’s
property, plant and equipment is reflected at original cost since such assets
remain subject to rate regulation on a historical cost basis. In addition to its
wholly owned facilities, the Company holds a 50% ownership interest in Yards
Creek Pumped Storage Facility, and its net book value was approximately $19.2
million as of December 31, 2004. The costs of normal maintenance, repairs
and minor replacements are expensed as incurred. The Company's accounting policy
for planned major maintenance projects is to recognize liabilities as they are
incurred.








22





The Company
provides for depreciation on a straight-line basis at various rates over the
estimated lives of property included in plant in service. The annualized
composite rate was approximately 2.1% in 2004, 2.8% in 2003, and 3.5% in 2002.
The reduced depreciation rates in 2004 and 2003 reflect reductions from the
NJBPU August 2003 rate decision.


****


**(E)**
    **ASSET
      IMPAIRMENTS-**





*Long-Lived
Assets*





The Company
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.





*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, the Company evaluates its goodwill for impairment
at least annually and would make such an evaluation more frequently if
indicators of impairment should arise. In accordance with the accounting
standard, if the fair value of a reporting unit is less than its carrying value
(including goodwill), the goodwill is tested for impairment. If an impairment is
indicated, the Company 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. The Company's 2004 annual review was completed in the third
quarter of 2004 with no impairment indicated. The forecasts used
in the Company's evaluation of goodwill reflect operations consistent with its
general business assumptions. Unanticipated changes in those assumptions could
have a significant effect on the Company's future evaluations of goodwill. As of
December 31, 2004, the Company had recorded goodwill of $2.0 billion
related to the merger. In 2004, the
Company adjusted goodwill for interest received on a pre-merger income tax
refund and for the reversal of tax valuation allowances related to income tax
benefits realized attributable to prior period capital loss carryforwards that
were offset by capital gains generated in 2004.





*Investments*





The Company
periodically evaluates 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.
The Company 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 Company's
investments are disclosed in Note 4.





**(F)**
    **COMPREHENSIVE
      INCOME-**





Comprehensive
income includes net income as reported on the Consolidated Statements of Income
and all other changes in common stockholder’s equity except those resulting from
transactions with FirstEnergy and preferred stockholders. As of
December 31, 2004, accumulated other comprehensive loss consisted of
unrealized losses on derivative instrument hedges of $2 million and a minimum
liability for unfunded retirement benefits of $53 million. As of December 31,
2003, accumulated other comprehensive loss consisted of unrealized losses on
derivative instrument hedges of $4 million and a minimum liability for unfunded
retirement benefits of $48 million.





**(G)**
    **INCOME
      TAXES-**





Details of the
total provision for income taxes are shown on the Consolidated Statements of
Taxes. The Company 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 used 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 carry forward 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. The Company is included in
FirstEnergy's consolidated federal income tax return. The consolidated tax
liability is allocated on a “stand-alone”
company basis, with the Company recognizing the tax benefit for any tax losses
or credits it contributes to the consolidated return.





23





**(H)**
    **TRANSACTIONS
      WITH AFFILIATED COMPANIES-**





Operating revenues,
operating expenses and other income included transactions with affiliated
companies, primarily FESC, GPUS and FES. GPUS (until it ceased operations in
mid-2003) and FESC have provided legal, accounting, financial and other services
to the Company. The Company also entered into sale and purchase transactions
with affiliates (Met-Ed and Penelec) during the period. Through the BGS auction
process, FES is a supplier of power to the Company. The primary affiliated
companies transactions are as follows:





**2004**
    
    **2003**
    
    **2002*****(In
      millions)*****Operating
      Revenues:**Wholesale
      sales-affiliated companies
    
    $
    49
    
    $
    36
    
    $
    18**Operating
      Expenses:**Service
      Company support services
    
    
    95
    
    
    101
    
    
    140Power
      purchased from other affiliates
    
    
    --
    
    
    --
    
    
    26Power
      purchased from FES
    
    
    71
    
    
    55
    
    
    18








FirstEnergy does
not bill directly or allocate any of its costs to any subsidiary company. Costs
are allocated to the Company from FESC, a subsidiary of FirstEnergy and a “mutual service company” as defined in Rule 93 of PUHCA. The majority of
costs are directly billed or assigned at no more than cost as determined by
PUHCA Rule 91. The remaining costs are for services that are provided on behalf
of more than one company, or costs that cannot be precisely identified and are
allocated using formulas that are filed annually with the SEC on Form U-13-60.
The current allocation or assignment formulas used and their bases include
multiple factor formulas: each company’s proportionate amount of FirstEnergy’s
aggregate direct payroll, number of employees, asset balances, revenues, number
of customers, other factors and specific departmental charge ratios. Management
believes that these allocation methods are reasonable. Intercompany transactions
with FirstEnergy and its other subsidiaries are generally settled under
commercial terms within thirty days, except for a net $48 million receivable
from affiliates for OPEB obligations.





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





FirstEnergy
 provides  noncontributory  defined  benefit pension
plans that cover substantially all of the Company's 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 (the Company's share
was $62 million). Prior to this contribution, projections indicated that cash
contributions of approximately $600 million would have been required during the
2006 to 2007 time period under minimum funding requirements established by the
IRS. The election to pre-fund the plan is expected to eliminate that funding
requirement. Since the contribution is deductible for tax purposes, the
after-tax cash impact of the voluntary contribution is approximately $300
million (the Company's share was $37 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.





24





Unless otherwise
indicated, the following tables provide information applicable to FirstEnergy’s
pension and OPEB plans.





**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
    )Company's
      share of net amount recognized
    
    $
    68
    
    $
    13
    
    $
    (79
    )
    $
    (89
    )Increase
      (decrease) in minimum liability
      included 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
      Category**Equity
      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








25








**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
    
    $
    114Company's
      share of net periodic cost (income)
    
    $
    7
    
    $
    12
    
    $
    (20
    )
    $
    5
    
    $
    12
    
    $
    5








**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 next
      year
      (pre/post-Medicare)
    
    
    9%-11
    %
    
    10%-12
    %Rate to which
      the cost trend rate is assumed to
      decline (the
      ultimate trend rate)
    
    
    5
    %
    
    5
    %Year that the
      rate reaches the ultimate trend
      rate
      (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
    )








26





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 the Company’s postretirement benefit costs by $2
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 the Company’s
net periodic postretirement benefit costs by $5 million during
2004.





As a result of its
voluntary contribution and the increased market value of pension plan assets,
the Company reduced its accrued benefit cost as of December 31, 2004 by $46
million. As prescribed by SFAS 87, the Company increased its additional minimum
liability by $9 million, offset by a charge to OCI. The balance in AOCL of $53
million (net of $37 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.**  **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 as of
December 31:








**2004**
    
    **2003****Carrying**
    
    **Fair**
    
    **Carrying**
    
    **Fair****Value**
    
    **Value**
    
    **Value**
    
    **Value*****(In
      millions)***Long-term
      debt
    
    $
    1,264
    
    $
    1,252
    
    $
    1,273
    
    $
    1,190








The fair values of
long-term debt 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 Company’s ratings.





27





*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:








**2004**
    
    **2003****Carrying**
    
    **Fair**
    
    **Carrying**
    
    **Fair****Value**
    
    **Value**
    
    **Value**
    
    **Value*****(In
      millions)***Debt
      securities:(1)-Government
      obligations
    
    $
    208
    
    $
    208
    
    $
    200
    
    $
    200-Corporate
      debt securities
    
    
    11
    
    
    11
    
    
    13
    
    
    13219
    
    
    219
    
    
    213
    
    
    213Equity
      securities(1)
    
    
    80
    
    
    80
    
    
    70
    
    
    70$
    299
    
    $
    299
    
    $
    283
    
    $
    283





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








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 Company has no securities held for trading purposes.
The following table summarizes the amortized cost basis, gross 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
    
    $
    55
    
    $
    3
    
    $
    --
    
    $
    58
    
    $
    53
    
    $
    4
    
    $
    --
    
    $
    57Equity
      securities
    
    
    72
    
    
    10
    
    
    2
    
    
    80
    
    
    54
    
    
    15
    
    
    --
    
    
    69$
    127
    
    $
    13
    
    $
    2
    
    $
    138
    
    $
    107
    
    $
    19
    
    $
    --
    
    $
    126








Proceeds from the
sale of decommissioning trust investments, gross 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
    
    $
    119
    
    $
    70
    
    $
    44Gross
      realized gains
    
    
    15
    
    
    1
    
    
    --Gross
      realized losses
    
    
    1
    
    
    --
    
    
    --Interest and
      dividend income
    
    
    4
    
    
    4
    
    
    4








28





The following table
provides the fair value and gross unrealized losses of 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
    
    $
    3
    
    $
    --
    
    $
    5
    
    $
    --
    
    $
    8
    
    $
    --Equity
      securities
    
    
    16
    
    
    2
    
    
    --
    
    
    --
    
    
    16
    
    
    2$
    19
    
    $
    2
    
    $
    5
    
    $
    --
    
    $
    24
    
    $
    2








The Company
periodically evaluates the securities held by its nuclear decommissioning trusts
for other-than-temporary impairment.  The Company 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 an impairment is other than
temporary. The Company's decommissioning trusts 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.





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.





**5.**
    **LEASES:**





Consistent with
regulatory  treatment, the rentals for capital and operating leases
are charged to operating expenses on the Consolidated Statements of Income. The
Company’s most significant operating lease relates to the sale and leaseback of
a portion of its ownership interest in the Merrill Creek Reservoir project. The
interest element related to this lease was $1.4 million, $1.4 million, and $1.2
million for the years 2004, 2003 and 2002, respectively.





As of
December 31, 2004, the future minimum lease payments on the Company’s
Merrill Creek operating lease, net of reimbursements from subleases, are: $1.7
million, $1.6 million, $1.6 million, $1.6 million and $2.1 million for the years
2005 through 2009, respectively, and $53.0 million for the years thereafter. The
Company is recovering its Merrill Creek lease payments, net of reimbursements,
through its distribution rates.





**6.**
    **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. The Company consolidates VIEs when it is determined to be the primary
beneficiary as defined by FIN 46R.





The Company 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 Company and the
contract price for power is correlated with the plant’s variable costs of
production. The Company maintains several long-term power purchase agreements
with NUG entities. The agreements were structured pursuant to the Public Utility
Regulatory Policies Act of 1978. The Company was not involved in the creation
of, and has no equity or debt invested in, these entities.





The Company has
determined that for all but six of these entities, the Company has no variable
interests in the entities or the entities are governmental or not-for-profit
organizations not within the scope of FIN 46R. The Company may hold variable
interests in the remaining six 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, the Company requests on a quarterly basis, the information necessary from
these entities to determine whether they are VIEs or whether the Company is the
primary beneficiary. The Company has been unable to obtain the requested
information, which in most cases, was deemed by the requested entity to be
proprietary. As such, the Company applied the scope exception that exempts
enterprises unable to obtain the necessary information to evaluate entities
under FIN 46R. The maximum exposure to loss from these entities results from
increases in the variable pricing component under the contract terms and cannot
be determined without the requested data. The purchased power costs from these
entities during 2004, 2003 and 2002, were $129 million, $115 million and $107
million, respectively.





29





**7.**
    **REGULATORY
      MATTERS:**





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, 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 for completion in
2004. Furthermore, FirstEnergy certified to NERC on June 30, 2004, with
minor exceptions noted, that we 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.





FirstEnergy is
proceeding with the implementation of the recommendations that were to be
implemented 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,
the Company 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 the Company'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 the Company'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, the Company and the NJBPU staff created a
Memorandum of Understanding (MOU) that set out specific tasks to be performed by
the Company and a timetable for completion. On March 29, 2004, the NJBPU adopted
the MOU and endorsed the Company'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. The Company continues to file compliance
reports reflecting activities associated with the MOU and
Stipulation.





The Company 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 the
Company's deferred balance upon application by the Company and a determination
by the NJBPU that the conditions of the New Jersey restructuring legislation are
met. On February 14, 2003, the Company 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.








30





In July 2003,
 the NJBPU  announced its JCP&L base electric  rate
proceeding decision, which reduced the Company'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 the
Company's rate base. The decision ordered that a Phase II proceeding be
conducted to review whether the Company is in compliance with current service
reliability and quality standards. The NJBPU also ordered that any expenditures
and projects undertaken by the Company 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 the Company's return on equity to 9.75% or decrease it to 9.25%,
depending on its assessment of the reliability of JCP&L's service. Any
reduction would be retroactive to August 1, 2003. The Company 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 of the original impairment
amount estimated in 2003. The Company 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,  the Company  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, the
Company submitted rebuttal testimony on January 4, 2005. Settlement conferences
are ongoing.





The Company
 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 the Company'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 the Company 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.





In accordance with
an April 28, 2004 NJBPU order, the Company 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, the Company
filed an updated TMI-2 decommissioning study (see Note 9 - Asset Retirement
Obligation). 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.





**8.**
    **CAPITALIZATION:**





**(A)**
    **RETAINED
      EARNINGS-**





In general, the
Company’s FMB indenture restricts the payment of dividends or distributions on
or with respect to the Company’s common stock to amounts credited to earned
surplus since the date of its indenture. As of December 31, 2004, the
Company had retained earnings available to pay common stock dividends of $41.5
million, net of amounts restricted under the Company’s FMB
indenture.





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





Preferred stock may
be redeemed by the Company, in whole or in part, with 30-90 days’ notice.





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





*Securitized
Transition Bonds*





On June 11,
2002, JCP&L Transition Funding LLC (Issuer), a wholly owned limited
liability company of the Company, sold $320 million of transition bonds to
securitize the recovery of the Company’s bondable stranded costs associated with
the previously divested Oyster Creek Nuclear Generating Station.








31





The Company does
not own, nor did it purchase, any of the transition bonds, which are included in
long-term debt on the Company’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. The Company, 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.
The Company is entitled to a quarterly servicing fee of $100,000 that is payable
from TBC collections.





*Other Long-term
Debt*





The
 Company’s  FMB indenture,  which secures all of the
Company’s  FMBs, serves as a direct first  mortgage lien on 
substantially all of the  Company’s property and franchises, other than
specifically excepted property.





The Company has
various debt covenants under its financing arrangements. The most restrictive of
these relate to the nonpayment of interest and/or principal on debt, which could
trigger a default. Cross-default provisions also exist between FirstEnergy and
the Company.





Based on the amount
of bonds authenticated by the Trustee through December 31, 2004, the
Company’s annual sinking fund requirements for all bonds issued under the
mortgage amount to $24 million. The Company expects to fulfill its sinking fund
obligation by providing refundable bonds to the Trustee.





Sinking fund
requirements for FMBs and maturing long-term debt for the next five years
are:








***(In
      millions)***2005
    
    $
    172006
    
    
    2082007
    
    
    182008
    
    
    192009
    
    
    25








**9.**
    **ASSET
      RETIREMENT OBLIGATION:**





In January 2003,
the Company implemented SFAS 143, which provides accounting standards for
retirement obligations associated with tangible long-lived assets. This
statement 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 asset
retirement liability 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.





The Company
identified applicable legal obligations as defined under the new standard for
nuclear power plant decommissioning. The ARO liability as of the date of
adoption of SFAS 143 was $103.9 million, including accumulated accretion for the
period from the date the liability was incurred to the date of adoption. As of
December 31, 2002, the Company recognized decommissioning liabilities of
$129.9 million. The Company expects substantially all nuclear decommissioning
costs to be recoverable through regulated rates. Therefore, a regulatory
liability of $26 million was recognized upon adoption of SFAS 143. The ARO
includes the Company's obligation for the nuclear decommissioning of. The
Company's share of the obligation to decommission TMI-2 was developed based on a
site-specific study performed by an independent engineer. The Company utilized
an expected cash flow approach to measure the fair value of the nuclear
decommissioning ARO. The Company maintains 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 $138 million.





In the third
quarter of 2004, the Company 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 net decrease in the Company's TMI-2 ARO
liability and corresponding regulatory asset was $43 million.





32





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





**Reconciliation**
    
    **2004**
    
    **2003*****(In
      millions)***Beginning
      balance as of January 1
    
    $
    110
    
    $
    104Accretion
    
    
    5
    
    
    6Revision in
      estimated cash flows
    
    
    (42
    )
    
    --**Ending
      balance as of December 31**
    
    $
    73
    
    $
    110








The following table
provides the year-end balance of the ARO related to nuclear decommissioning 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
    
    $
    98Accretion
    
    
    6**Ending
      balance as of December 31**
    
    **$**
    **104**








**10.**
    **SHORT-TERM
      BORROWINGS:**





The Company may
borrow from its affiliates on a short-term basis. As of December 31, 2004,
the Company had total short-term borrowings outstanding of $248.5 million from
its affiliates with an interest rate of 2.0%





**11.**
    **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. Based on its present
ownership interest in TMI-2, the Company is exempt from any potential assessment
under the industry retrospective rating plan.





The Company is also
insured as to its interest in TMI-2 under a policy issued to the operating
company for the plant. Under this policy, $150 million is provided for property
damage and decontamination and decommissioning costs. Under this policy, the
Company can be assessed a maximum of approximately $0.2 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 Company intends
to maintain insurance against nuclear risks as described above as long as it is
available. To the extent that property damage, decontamination, decommissioning,
repair and replacement costs and other such costs arising from a nuclear
incident at TMI-2 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 Company’s insurance policies, or to the extent such insurance
becomes unavailable in the future, the Company would remain at risk for such
costs.





**(B)**
    **ENVIRONMENTAL
      MATTERS-**





The Company has
been named as a PRP at waste disposal sites which may require cleanup under the
Comprehensive Environmental Response, Compensation and Liability Act of 1980.
Allegations of disposal of hazardous substances at historical sites and the
liability involved are often unsubstantiated and subject to dispute; however,
federal law provides that all PRPs for a particular site are liable on a joint
and several basis. Therefore, environmental liabilities that are considered
probable have been recognized on the Consolidated Balance Sheets, based on
estimates of the total costs of cleanup, the Company's proportionate
responsibility for such costs and the financial ability of other nonaffiliated
entities to pay. In addition, the Company has accrued liabilities for
environmental remediation of former manufactured gas plants in New Jersey; those
costs are being recovered by the Company through a non-bypassable SBC. The
Company has accrued liabilities aggregating approximately $47 million as of
December 31, 2004. The Company accrues environmental liabilities only when
it concludes that it is probable that an obligation for such costs exists and
can reasonably determine the amount of such costs. Unasserted claims are
reflected in the Company's determination of environmental liabilities and are
accrued in the period that they are both probable and reasonably
estimable.








33





**(C)**
    **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.





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, and ECAR, and other parties to correct the causes of the
August 14, 2003 power outages. 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 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.





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





*Legal
Matters*





There are various
lawsuits, claims (including claims for asbestos exposure) and proceedings
related to the Company's normal business operations pending against the Company,
the most significant of which are described herein.





34





**12.**
    **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. The Company is currently evaluating this standard but
does not expect it to have a material impact on the financial
statements.





*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 the Company after June 30, 2005. The Company 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, the Company 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 the Company
in the third quarter of 2004 and did not affect the Company's financial
statements.





*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 the Company's
consolidated financial statements is described in Note 3.





35





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








**March
      31,**
    
    **June
      30,**
    
    **September
      30,**
    
    **December
      31,****Three
      Months Ended**
    
    **2004**
    
    **2004**
    
    **2004**
    
    **2004****(a)*****(In
      millions)***Operating
      Revenues
    
    $
    498.1
    
    $
    549.6
    
    $
    706.6
    
    $
    452.7Operating
      Expenses and Taxes
    
    
    466.1
    
    
    494.7
    
    
    634.5
    
    
    427.8Operating
      Income
    
    
    32.0
    
    
    54.9
    
    
    72.1
    
    
    24.9Other Income
    
    
    1.5
    
    
    1.1
    
    
    2.0
    
    
    3.2Net Interest
      Charges
    
    
    20.1
    
    
    19.2
    
    
    21.8
    
    
    18.9Net
      Income
    
    $
    13.4
    
    $
    36.8
    
    $
    52.3
    
    $
    9.2Earnings on
      Common Stock
    
    $
    13.3
    
    $
    36.7
    
    $
    52.2
    
    $
    8.9








**March
      31,**
    
    **June
      30,**
    
    **September
      30,**
    
    **December
      31,****Three
      Months Ended**
    
    **2003**
    
    **2003**
    
    **2003**
    
    **2003****(*****In
      millions)***Operating
      Revenues
    
    $
    657.0
    
    $
    542.8
    
    $
    741.3
    
    $
    418.6Operating
      Expenses and Taxes
    
    
    581.6
    
    
    564.5
    
    
    653.8
    
    
    413.0Operating
      Income (Loss)
    
    
    75.4
    
    
    (21.7
    )
    
    87.5
    
    
    5.6Other Income
    
    
    1.2
    
    
    2.3
    
    
    0.6
    
    
    3.0Net Interest
      Charges
    
    
    22.5
    
    
    22.4
    
    
    20.5
    
    
    20.4Net Income
      (Loss)
    
    $
    54.1
    
    $
    (41.8
    )
    $
    67.6
    
    $
    (11.8
    )Earnings
      (Loss) Applicable
      to Common
      Stock
    
    $
    53.9
    
    $
    (41.4
    )
    $
    67.4
    
    $
    (11.8
    )








(a)
    Net income
      for the quarter ended December 31, 2004 includes an adjustment relating to
      periods prior to October 1, 2004, that decreased amortization expense and
      increased regulatory assets by $3.8 million ($2.2 million after tax). The
      adjustment corrects the accumulated amortization of the MTC deferred
      balance due to a revised MTC Tariff that became effective on August 1,
      2003. Management concluded that the adjustment was not material to the
      reported results of operations for any quarter of 2003 and 2004, nor was
      it material to the consolidated balance sheets and consolidated statements
      of cash flows for any of those
quarters.