**METROPOLITAN EDISON COMPANY**

**2004 ANNUAL REPORT TO STOCKHOLDERS**


Metropolitan
Edison Company is a wholly owned electric utility subsidiary of FirstEnergy
Corp. It engages in the distribution and sale of electric energy in eastern and
south central Pennsylvania. The area it serves has a population of approximately
1.2 million.





**Contents**
    
    **Page**Glossary of Terms
    
    
    i-iiManagement Reports
    
    
    1Report of Independent Registered Public Accounting
      Firm
    
    
    2Selected Financial Data
    
    
    3Management's Discussion and Analysis
    
    
    4-13Consolidated Statements of Income
    
    
    14Consolidated Balance Sheets
    
    
    15Consolidated Statements of Capitalization
    
    
    16Consolidated Statements of Common Stockholder's
      Equity
    
    
    17Consolidated Statements of Preferred Stock
    
    
    17Consolidated Statements of Cash Flows
    
    
    18Consolidated Statements of Taxes
    
    
    19Notes to Consolidated Financial Statements
    
    
    20-36


**GLOSSARY OF TERMS**

The following
abbreviations and acronyms are used in this report to identify Metropolitan
Edison 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 Company, an affiliated
      New Jersey electric utilityMet-Ed
    Metropolitan Edison CompanyMYR
    MYR Group, Inc., a utility infrastructure construction
      service companyOE
    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:ALJ
    Administrative Law JudgeAOCL
    Accumulated Other Comprehensive LossAPB
    Accounting Principles BoardAPB 25
    APB Opinion No. 25, "Accounting for Stock Issued to
      Employees"ARO
    Asset Retirement ObligationCTC
    Competitive Transition ChargeECAR
    East Central Area Reliability CoordinationFASB
    Financial Accounting Standards BoardFERC
    Federal Energy Regulatory CommissionFIN
    FASB InterpretationFIN 46R
    FIN 46 (revised December 2003), "Consolidation of Variable
      Interest Entities"FMB
    First Mortgage BondsFSP
    FASB Staff PositionFSP EITF 03-1-1
    FASB Staff Position No. EITF Issue 03-1-1, "Effective Date
      of Paragraphs 10-20 of EITF Issue
      No. 03-1, The Meaning of Other-Than-Temporary Impairment and
      Its Application to Certain Investments*"*EITF 97-4
    EITF Issue No. 97-4, "Deregulation of the Pricing of
      Electricity - Issues Related to the Application of FASB Statements No. 71
      and 101"FSP 106-1
    FASB Staff Position No.106-1, "Accounting and Disclosure
      Requirements Related to the Medicare
      Prescription Drug, Improvement and Modernization Act of
      2003"FSP 106-2
    FASB Staff Position No.106-2, "Accounting and Disclosure
      Requirements Related to the Medicare
      Prescription Drug, Improvement and Modernization Act of
      2003"FSP 109-1
    FASB Staff Position No. 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"GAAP
    Accounting Principles Generally Accepted in the United
      StatesIRS
    Internal Revenue ServiceKWH
    Kilowatt-hoursMedicare Act
    Medicare Prescription Drug, Improvement and Modernization
      Act of 2003MISO
    Midwest Independent Transmission System Operator,
      Inc.Moody’s
    Moody’s Investors ServiceNERC
    North American Electric Reliability CouncilNUG
    Non-Utility GenerationOCI
    Other Comprehensive IncomeOPEB
    Other Post-Employment BenefitsPJM
    PJM Interconnection L. L. C.PLR
    Provider of Last Resort



i

**GLOSSARY OF TERMS, Cont'd**
PPUC
    Pennsylvania Public Utility CommissionPRP
    Potentially Responsible PartyPUCO
    Public Utilities Commission of OhioPUHCA
    Public Utility Holding Company ActRTC
    Regulatory Transition ChargeS&P
    Standard & Poor's Ratings ServiceSEC
    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 106
    SFAS No. 106, "Employers' Accounting for Postretirement
      Benefits Other Than Pensions"SFAS 133
    SFAS No. 133, "Accounting for Derivative Instruments and
      Hedging Activities"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 EntityTMI-1
    Three Mile Island Unit 1TMI-2
    Three Mile Island Unit 2VIE
    Variable Interest Entity




ii**MANAGEMENT REPORTS**

*Management's Responsibility for Financial
Statements*

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

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

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

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

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

1**Report of Independent Registered Public Accounting
Firm**


To the Stockholders and Board of
Directors of Metropolitan Edison Company:

We have completed an integrated audit of Metropolitan Edison
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 Metropolitan Edison 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 2(G) 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 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
**METROPOLITAN EDISON COMPANY**

**SELECTED FINANCIAL DATA**


**2004**
    
    **2003**
    
    **2002**
    
    **Nov. 7 -**
      **Dec. 31, 2001**
    
    **Jan. 1 -**
      **Nov. 6, 2001**
    
    **2000*****(Dollars in
thousands)***Operating Revenues
    
    $
    1,070,847
    
    $
    969,788
    
    $
    986,608
    
    $
    143,760
    
    
    $         824,556
    
    $
    842,333Operating Income
    
    $
    86,197
    
    $
    83,938
    
    $
    91,271
    
    $
    17,367
    
    
    $         102,247
    
    $
    135,211Income Before Cumulative Effect
      Of Accounting Change
    
    $
    66,955
    
    $
    60,953
    
    $
    63,224
    
    $
    14,617
    
    
    $         
    62,381
    
    $
    81,895Net Income
    
    $
    66,955
    
    $
    61,170
    
    $
    63,224
    
    $
    14,617
    
    
    $         
    62,381
    
    $
    81,895Total Assets
    
    $
    3,245,278
    
    $
    3,473,987
    
    $
    3,564,805
    
    $
    3,607,187
    
    
    
    
    $
    2,708,062**Capitalization as of December 31:**Common Stockholder’s Equity
    
    $
    1,285,419
    
    $
    1,292,667
    
    $
    1,315,586
    
    $
    1,288,953
    
    
    
    
    $
    537,013Company-Obligated Trust
      Preferred Securities
    
    
    --
    
    
    --
    
    
    92,409
    
    
    92,200
    
    
    
    
    
    100,000Long-Term Debt and Other Long-
      Term Obligations
    
    
    701,736
    
    
    636,301
    
    
    538,790
    
    
    583,077
    
    
    
    
    
    496,860Total Capitalization
    
    $
    1,987,155
    
    $
    1,928,968
    
    $
    1,946,785
    
    $
    1,964,230
    
    
    
    
    $
    1,133,873**Capitalization Ratios:**Common Stockholder’s Equity
    
    
    64.7
    %
    
    67.0
    %
    
    67.6
    %
    
    65.6
    %
    
    
    
    
    47.4
    %Company-Obligated Trust
      Preferred Securities
    
    
    --
    
    
    --
    
    
    4.7
    
    
    4.7
    
    
    
    
    
    8.8Long-Term Debt and Other Long-
      Term Obligations
    
    
    35.3
    
    
    33.0
    
    
    27.7
    
    
    29.7
    
    
    
    
    
    43.8Total Capitalization
    
    
    100.0
    %
    
    100.0
    %
    
    100.0
    %
    
    100.0
    %
    
    
    
    
    100.0
    %**Distribution Kilowatt-Hour Deliveries
      (Millions):**Residential
    
    
    5,071
    
    
    4,900
    
    
    4,738
    
    
    793
    
    
    3,712
    
    
    4,377Commercial
    
    
    4,251
    
    
    4,034
    
    
    3,991
    
    
    652
    
    
    3,203
    
    
    3,699Industrial
    
    
    4,042
    
    
    4,047
    
    
    3,972
    
    
    662
    
    
    3,506
    
    
    4,412Other
    
    
    33
    
    
    36
    
    
    35
    
    
    6
    
    
    27
    
    
    38Total
    
    
    13,397
    
    
    13,017
    
    
    12,736
    
    
    2,113
    
    
    10,448
    
    
    12,526**Customers Served:**Residential
    
    
    464,287
    
    
    455,073
    
    
    448,334
    
    
    442,763
    
    
    
    
    
    436,573Commercial
    
    
    59,495
    
    
    58,825
    
    
    58,010
    
    
    57,278
    
    
    
    
    
    56,080Industrial
    
    
    1,868
    
    
    1,906
    
    
    1,936
    
    
    1,961
    
    
    
    
    
    1,967Other
    
    
    730
    
    
    732
    
    
    728
    
    
    819
    
    
    
    
    
    810Total
    
    
    526,380
    
    
    516,536
    
    
    509,008
    
    
    502,821
    
    
    
    
    
    495,430


3**METROPOLITAN EDISON 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 net income in 2003 and 2002.

**Results of Operations**

Net income increased to $67 million in 2004, compared to $61
million in 2003, due to higher operating revenues partially offset by higher
purchased power costs and other operating costs. Net income decreased to $61
million in 2003, compared to $63 million in 2002, due to lower operating
revenues and increased operating expenses, including higher employee benefit
costs and storm restoration expenses. These reductions to net income were
partially offset by lower purchased power costs, principally due to reduced
quantities of power purchased through two-party agreements. Net interest charges
were lower in 2003 due to debt redemptions and the refinancing of higher-rate
debt.

Operating
revenues increased by $101 million in 2004, primarily as a result of increases
of $31 million and $36 million in retail generation sales and distribution
throughput revenues, respectively. The higher generation sales revenues reflect
the effect of an 11.8% increase in sales volume partially offset by lower
composite prices. The volume increase was due to 8.5% and 34.6% increases,
respectively, in sales to the commercial and industrial sectors as a result of
customers returning to us from alternate suppliers. Sales by alternative
suppliers as a percent of total sales delivered in our franchise area decreased
by 2.9 and 20.2 percentage points for commercial and industrial customers,
respectively. Higher revenues of $36 million from electricity throughput in 2004
from 2003 were due to higher prices and a 2.9% increase in distribution
deliveries. The higher volume reflected an increase in the retail customer base
and an improving economy, partially offset by cooler weather in the summer
months of 2004. The higher distribution prices were due to the PPUC
Restructuring Settlement order (see Regulatory Matters) with a corresponding
decrease in retail generation prices. Also contributing to the revenue increase
was $34 million of PJM network transmission system revenue, Financial
Transmission Rights (FTR)/Auction Revenue Rights (ARR), and PJM congestion
credit revenues related to transmission transactions we assumed in 2004 due to a
change in our power supply agreement with FES, which also increased transmission
expenses by $51 million, as discussed below.

The significant decrease in customer shopping in 2004 reflects our
low generation price as provider of last resort. Alternative suppliers have not
been able to match that price by a sufficient margin to ensure profitability,
particularly in the industrial sector.
4Operating
revenues decreased by $17 million in 2003, compared to 2002. The decrease in
2003 was the result of wholesale sales revenues decreasing $25 million
principally due to a reduction in kilowatt-hour sales to affiliate companies and
other wholesale customers. An increase in the number of commercial and
industrial customers receiving their power from alternate suppliers also
contributed to the decrease in operating revenues. Distribution deliveries
benefited from higher demand by residential (3.4%), commercial (1.0%), and
industrial (1.9%) customers due in large part to colder temperatures in early
2003, which were partially offset by milder summer weather.

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

**Changes in Kilowatt-hour Sales**
    
    **2004**
    
    **2003*****Increase
      (Decrease)***Electric Generation:Retail
    
    
    11.8
    %
    
    1.2
    %Wholesale
    
    
    209.1
    %
    
    (100.0
    )%**Total Electric Generation Sales**
    
    
    **12.0**
    **%**
    
    **(6.1**
    **)%**Distribution Deliveries:Residential
    
    
    3.5
    %
    
    3.4
    %Commercial
    
    
    5.4
    %
    
    1.0
    %Industrial
    
    
    (0.1
    )%
    
    1.9
    %**Total Distribution Deliveries**
    
    
    **2.9**
    **%**
    
    **2.2**
    **%**

*Operating
Expenses and Taxes*

Total
operating expenses and taxes increased $99 million or 11.2% in 2004 and
decreased $9 million in 2003:

**Operating Expenses and Taxes -
      Changes**
    
    **2004**
    
    **2003****Increase
    (Decrease)**
    
    ***(In millions)***Purchased power costs
    
    $
    64
    
    $
    (6
    )Other operating costs
    
    
    32
    
    
    3Provision for depreciation
    
    
    (3
    )
    
    (6
    )Amortization of regulatory assets
    
    
    8
    
    
    --General taxes
    
    
    3
    
    
    --Income taxes
    
    
    (5
    )
    
    --**Total operating expenses and
    taxes**
    
    **$**
    **99**
    
    **$**
    **(9**
    **)**

Purchased power costs increased by $64 million in 2004, compared
with 2003, primarily due to a 10.7% increase in kilowatt-hour purchases to meet
higher retail generation sales requirements. Other operating costs increased by
$32 million primarily due to PJM congestion and ancillary transmission expenses
that we assumed in 2004 due to a change in our power supply agreement with FES.
Depreciation expense decreased in 2004 due to fully depreciating the Energy
Management System in 2003. Amortization of regulatory assets increased primarily
due to higher regulatory asset amortization from higher revenue recovery of
above market NUG costs in 2004. General taxes increased $3 million in 2004
primarily due to higher payroll and gross receipt taxes.

Total
operating expenses and taxes decreased $9 million in 2003 compared to 2002. The
majority of the decrease resulted from decreases in purchased power costs and
depreciation expense, partially offset by higher other operating costs.
Purchased power costs decreased by $6 million in 2003 because of reduced
kilowatt hours required for customer needs during 2003, partially offset by
slightly higher unit costs. The decrease in depreciation charges in 2003,
compared to 2002, reflected a reduced depreciable asset base. Other operating
costs increased in 2003 primarily due to increased costs to restore customer
service resulting from significant storm activity and higher employee benefit
costs.

*Other
Income*

Other income
increased $4 million in 2004, compared to 2003, due to a $2 million increase in
the return on CTC stranded generation regulatory assets, and $2 million of
interest income on federal income tax refunds.

*Net
Interest Charges*

Interest on
long-term debt increased by $4 million in 2004 as a result of increased debt
outstanding from the issuance of $250 million of senior notes in the second
quarter of 2004, partially offset by the retirement of $99 million of
medium term notes and $100 million of preferred securities during the year. This
increase was offset by a $4 million reduction in interest on company
obligated manditorily redeemable preferred securities due to the redemption of
all of the trust preferred securities in 2004.
5
Net interest
charges decreased by $5 million in 2003, compared to 2002. The decrease reflects
the refinancing of higher-cost debt in the first quarter of 2003.

*Cumulative
Effect of Accounting Change*

Upon adoption
of SFAS 143 in the first quarter of 2003, we recorded an after-tax credit to net
income of $217,000. The cumulative effect adjustment for unrecognized
depreciation, accretion offset by the reduction in the existing decommissioning
liabilities and ceasing the accounting practice of depreciating non-regulated
generation assets using a cost of removal component was a $371,000 increase to
income, or $217,000 net of income taxes.

**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 a combination of cash from operations and
funds from the capital markets.

*Changes in
Cash Position*

As of
December 31, 2004, we had $120,000 of cash and cash equivalents compared
with $121,000 as of December 31, 2003. The major sources for changes in
these balances are summarized below.

*Cash Flows
From Operating Activities*

Cash flows
provided from operating activities totaled $74 million in 2004, $132 million in
2003 and $102 million in 2002. The sources of these changes are as
follows:

**Operating
      Cash Flows**
    
    **2004**
    
    **2003**
    
    **2002*****(In
      millions)***Cash earnings
      (1)
    
    $
    151
    
    $
    180
    
    $
    146Pension trust
      contribution(2)
    
    
    (23
    )
    
    --
    
    
    --Working
      capital
    
    
    (54
    )
    
    (48
    )
    
    (44
    )Total
    
    $
    74
    
    $
    132
    
    $
    102

(1) Cash earnings is a non-GAAP measure (see
reconciliation below).
(2) Pension trust contribution net of $16 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)
    
    $
    67
    
    $
    61
    
    $
    63Non-Cash Charges (Credits):Provision
      for depreciation
    
    
    41
    
    
    44
    
    
    51Amortization
      of regulatory assets
    
    
    106
    
    
    98
    
    
    98Deferred
      costs recoverable as regulatory assets
    
    
    (66
    )
    
    (71
    )
    
    (86
    )Deferred
      income taxes and investment tax credits
    
    
    3
    
    
    46
    
    
    23Other
      non-cash expenses
    
    
    --
    
    
    2
    
    
    (3
    )**Cash earnings (Non-GAAP)**
    
    **$**
    **151**
    
    **$**
    **180**
    
    **$**
    **146**

Net cash
provided from operating activities decreased $58 million during 2004, compared
with 2003. The decrease consisted of lower cash earnings of $29 million, a $23
million after-tax voluntary pension trust contribution in 2004, and a $6 million
decrease from changes in working capital. The decrease in cash earnings reflects
changes in deferred income tax expense partially offset by other changes as
described under "Results of Operations". The decrease in working capital was
principally due to changes in receivables partially offset by increases in
accounts payable balances. Net cash from operating activities increased by $30
million in 2003 compared to 2002 due to a $34 million increase in cash earnings
partially offset by a $4 million decrease in working capital. The increase in
cash earnings reflects changes in deferred income tax expense; the working
capital decrease primarily reflected changes in receivables partially offset by
changes in accrued tax balances.6
*Cash Flows
From Financing Activities*

In 2004, net
cash provided from financing activities was $11 million, including $247 million
in proceeds from the issuance of unsecured senior notes during the first quarter
of 2004, and $15 million in short-term borrowings. The new financing was
partially offset by the redemption of $100 million of unsecured subordinated
debentures, $90 million of redeemed first mortgage bonds, redemption of $6
million of other unsecured obligations, and $55 million of common stock dividend
payments.

In 2003, net
cash used for financing activities of $88 million reflects redemptions of
long-term debt of $260 million, repayment of $23 million of short-term
borrowings, and $52 million of common stock dividend payments to FirstEnergy,
partially offset by $248 million in proceeds from the issuance of secured notes.
In 2002, net cash used for financing activities of $54 million reflects
redemption of $60 million debt and $60 million of common stock dividend payments
to FirstEnergy, partially offset by $50 million in proceeds from the issuance of
secured notes, and a $16 million increase in short-term borrowings.

The following
table provides details regarding new issues and redemptions during each
year:


**Securities Issued or Redeemed**
    
    **2004**
    
    **2003**
    
    **2002**New IssuesSecured
      notes
    
    $
    --
    
    $
    248
    
    $
    50Unsecured
      notes
    
    
    247
    
    
    **--**
    
    
    **--**RedemptionsFirst
      Mortgage Bonds
    
    $
    90
    
    $
    260
    
    $
    60Subordinated
      Debentures
    
    
    100
    
    
    --
    
    
    --Other -
      Cowanesque
    
    
    6
    
    
    --
    
    
    --$
    196
    
    $
    260
    
    $
    60Short-term Borrowings, net source /(use) of cash
    
    $
    15
    
    $
    (23
    )
    $
    16


In March 2004, we completed a receivables financing arrangement
that provides borrowings of up to $80 million. The borrowing rate is based
on bank commercial paper rates. We are required to pay an annual facility fee of
0.30% on the entire finance limit. The facility was undrawn as of
December 31, 2004 and matures on March 29, 2005. We plan to renew the
agreement.

We have $80
million of short-term indebtedness at the end of 2004, compared to $65 million
at the end of 2003. We have obtained authorization from the SEC to incur
short-term debt up to $250 million (including the utility money pool). Under the
terms of our senior note indenture, we are no longer permitted to issue FMB so
long as senior notes are outstanding. These receivables financing arrangements
are expected to be renewed prior to expiration.

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, as well as
proceeds available from bank borrowings. Companies receiving a loan under the
money pool agreements must repay the principal amount of such loan, together
with accrued interest, within 364 days of borrowing the funds. The rate of
interest is the same for each company receiving a loan from 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 that of FirstEnergy. On
August 26, 2004, S&P lowered its rating on certain of our Senior
Notes to BBB- from BBB. The rationale for the ratings change was that our senior
secured notes, in aggregate, now comprise greater than 80% of our total debt
outstanding. According to the terms of the senior note indenture, once the 80%
threshold is reached, the collateral mortgage bond security falls away and all
senior secured notes that were secured by our senior note indenture become
unsecured. The one notch lower rating reflects this loss of collateral security.
The BBB senior secured rating on our first mortgage bonds remained
unchanged.7
The following
table shows the securities ratings as of December 31, 2004. The ratings
outlook from the ratings agencies on all securities is stable.

**Ratings of
Securities****Securities**
    
    
    **S&P**
    
    
    **Moody’s**
    
    
    **Fitch****FirstEnergy**
    
    
    Senior unsecured
    
    
    BB+
    
    
    Baa3
    
    
    BBB-**Met-Ed**
    
    
    Senior secured
    
    
    BBB
    
    
    Baa1
    
    
    BBB+Senior unsecured
    
    
    BBB-
    
    
    Baa2
    
    
    BBB

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 for
investing activities totaled $85 million in 2004 and $60 million in 2003. The
increase resulted from a $10 million increase in property additions, $1 million
of additional loans to associated companies, and a $9 million capital transfer
from FESC.

Cash used for
investing activities totaled $60 million in 2003 and $58 million in 2002. The
net cash flows used for investing activities during 2003 resulted from property
additions, decommissioning trust investments, and loans to associated companies.
Cash used for investing activities during 2002 were for property additions
primarily to support our energy delivery operations and decommissioning trust
investments.

Our capital
spending for the period 2005 through 2007 is expected to be about $205 million
for property additions and energy delivery related improvements, of which
approximately $67 million applies to 2005.

**Contractual Obligations**

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


**2006-**
    
    **2008-****Contractual Obligations**
    
    **Total**
    
    **2005**
    
    **2007**
    
    **2009**
    
    **Thereafter*****(In millions)***Long-term debt (3)
    
    $
    730
    
    $
    30
    
    $
    151
    
    $
    7
    
    $
    542Short-term borrowings
    
    
    80
    
    
    80
    
    
    --
    
    
    --
    
    
    --Operating leases (1)
    
    
    49
    
    
    1
    
    
    3
    
    
    3
    
    
    42Purchases (2)
    
    
    2,922
    
    
    309
    
    
    804
    
    
    745
    
    
    1,064Total
    
    $
    3,781
    
    $
    420
    
    $
    958
    
    $
    755
    
    $
    1,648

(1) Operating lease payments
are net of reimbursements from sublessees (see Note 5 - Leases)
(2) Power purchases under
contracts with fixed or minimum quantities and approximate timing
(3) 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 and interest rate 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.8
*Commodity
Price Risk*

We are exposed
to market risk primarily due to fluctuations in electricity, natural gas, coal,
nuclear fuel and emission allowance prices. To manage the volatility relating to
these exposures, we use a variety of non-derivative and derivative instruments,
including forward contracts, options, futures contracts and swaps. The
derivatives are used principally for hedging purposes and, to a much lesser
extent, for trading purposes. Most of our non-hedge derivative contracts
represent non-trading positions that do not qualify for hedge treatment under
SFAS 133. The change in the fair value of commodity derivative contracts related
to energy production during 2004 is summarized in the following table:

**Increase in the Fair Value of Derivative
      Contracts**
    
    **Non-Hedge**
    
    **Hedge**
    
    **Total*****(In millions)***Change in the fair value of commodity
      derivative contractsOutstanding net asset as of January 1, 2004
    
    $
    31
    
    $
    --
    
    $
    31New contract value when entered
    
    
    --
    
    
    --
    
    
    --Additions/Increase in value of existing contracts
    
    
    1
    
    
    --
    
    
    1Change in techniques/assumptions
    
    
    --
    
    
    --
    
    
    --Settled contracts
    
    
    --
    
    
    --
    
    
    --**Net Assets - Derivatives Contracts as of December
      31, 2004****(1)**
    
    **$**
    **32**
    
    **$**
    **--**
    
    **$**
    **32****Impact of Changes in Commodity Derivative
      Contracts**(2)Income Statement Effects (Pre-Tax)
    
    $
    1
    
    $
    --
    
    $
    1Balance Sheet Effects:OCI (Pre-Tax)
    
    $
    --
    
    $
    --
    
    $
    --

(1)
    Includes $31 million in non-hedge commodity derivative
      contracts, which are offset by a regulatory
liability.
(2)
    Represents the increase in value of existing contracts,
      settled contracts and changes in techniques/
assumptions.

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


**Non-Hedge**
    
    **Hedge**
    
    **Total*****(In millions)*****Current-**Other
      Assets
    
    $
    --
    
    $
    --
    
    $
    --Other
      liabilities
    
    
    --
    
    
    --
    
    
    --**Non-Current-**Other
      Deferred Charges
    
    
    32
    
    
    --
    
    
    32Other
      noncurrent liabilities
    
    
    --
    
    
    --
    
    
    --**Net
      assets**
    
    **$**
    **32**
    
    **$**
    **--**
    
    **$**
    **32**

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


**Source of Information - Fair Value by Contract
      Year**
    
    **2005**
    
    **2006**
    
    **2007**
    
    **2008**
    
    **Thereafter**
    
    **Total*****(In millions)***Other external sources (1)
    
    
    10
    
    
    4
    
    
    --
    
    
    --
    
    
    --
    
    
    14Prices based on models
    
    
    --
    
    
    --
    
    
    6
    
    
    5
    
    
    7
    
    
    18**Total**(2)
    
    **$**
    **10**
    
    **$**
    **4**
    
    **$**
    **6**
    
    **$**
    **5**
    
    **$**
    **7**
    
    **$**
    **32**

(1)
    Broker
      quote sheets.
(2)   Includes $31 million from an embedded
option that is offset by a regulatory liability and does not affect
earnings.9
We perform
sensitivity analyses to estimate our exposure to the market risk of our
commodity positions. A hypothetical 10% adverse shift in quoted market prices in
the near term on both our trading and nontrading derivative instruments would
not have had a material effect on our consolidated financial position or cash
flows as of December 31, 2004. We estimate that if energy commodity prices
experienced an adverse 10% change, net income for the next twelve months would
not change, as the prices for all commodity positions are already above the
contract price caps.

*Interest
Rate Risk*

We are subject
to the inherent interest rate risks related to refinancing maturing debt by
issuing new debt securities. Our exposure to fluctuations in market interest
rates is reduced since our debt has fixed interest rates, as noted in the
following table.

**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
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    83
    
    **$**
    **83**
    
    **$**
    **83**Average interest rate
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    4.7
    %
    
    4.7
    %LiabilitiesLong-term Debt and Other
      Long-Term Obligations:Fixed rate
    
    $
    30
    
    $
    101
    
    $
    50
    
    $
    7
    
    
    
    
    $
    542
    
    **$**
    **730**
    
    **$**
    **731**Average interest rate
    
    
    6.8
    %
    
    5.7
    %
    
    5.9
    %
    
    6.0
    %
    
    
    
    
    4.9
    %
    
    5.2
    %Short-term Borrowings
    
    
    80
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    **$**
    **80**
    
    **$**
    **80**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 $134 million and $114 million as of
December 31, 2004 and 2003, respectively. A hypothetical 10% decrease in
prices quoted by stock exchanges would result in a $13 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. The PPUC authorized our rate
restructuring plan, establishing separate charges for transmission,
distribution, generation and stranded cost recovery, which is recovered through
a CTC. Customers electing to obtain power from an alternative supplier have
their bills reduced based on the regulated generation component, and the
customers receive a generation charge from the alternative supplier. We have a
continuing responsibility referred to as our PLR obligation to provide power to
those customers not choosing to receive power from an alternative energy
supplier, subject to certain limits.

We recognize,
as regulatory assets, costs which the PPUC and the FERC 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 when incurred.
All regulatory assets are expected to be recovered under the provisions of the
regulatory plan. Our regulatory assets totaled $693 million and $1 billion as of
December 31, 2004 and December 31, 2003, respectively.

*Regulatory
Matters*

We purchase a
portion of our PLR requirements from FES through a wholesale power sale
agreement. The PLR sale is automatically extended for each successive calendar
year unless any party elects to cancel the agreement by November 1 of the
preceding year. Under the terms of the wholesale agreement, FES retains the
supply obligation and the supply profit and loss risk, for the portion of power
supply requirements that we do not obtain under our NUG contracts and other
power contracts with nonaffiliated third party suppliers. This arrangement
reduces our exposure to high wholesale power prices by providing power at a
fixed price for our uncommitted PLR energy costs during the term of the
agreement with FES. We are authorized to continue deferring differences between
NUG contract costs and current market prices.10
On
January 12, 2005, we filed, before the PPUC, a request for deferral of
transmission-related costs beginning January 1, 2005 estimated to be
approximately $4 million per month. Various parties have intervened in this
case.

See Note 7 to
the consolidated financial statements for a more complete and detailed
discussion of regulatory matters in Pennsylvania.

*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 $26,000 as of December 31, 2004.

*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.

*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
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 were indicated, we would
recognize a loss - calculated as the difference between the implied fair value
of our goodwill and the carrying value of the goodwill. Our annual review was
completed in the third quarter of 2004, with no impairment of goodwill
indicated. The forecasts used in our evaluation 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. In the year ended December 31, 2004, we adjusted goodwill related
to interest received on a pre-merger income tax refund and for the reversal of
tax valuation allowances related to income tax benefits realized attributable to
prior period capital loss carryforwards that were used to offset capital gains
generated in 2004. As of December 31, 2004, we had recorded goodwill of
approximately $870 million.

*Regulatory
Accounting*

We are subject
to regulation that sets the prices (rates) it is permitted to charge its
customers based on the costs that the regulatory agencies determine the company
is permitted to recover. At times, regulators permit the future recovery through
rates of costs that would be currently charged to expense by an unregulated
company. This rate-making process results in the recording of regulatory assets
based on anticipated future cash inflows. 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.11
*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 a 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 $39 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 $23
million. As prescribed by SFAS 87, we increased our additional minimum liability
by $16 million, offset by a charge to OCI. The balance in AOCL of $42 million
(net of $30 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 its health care plans, and
projections of future medical trend rates.

*Long-Lived
Assets*

In accordance
with SFAS No. 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.12
*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.

**New Accounting Standards and Interpretations Adopted**

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

In March 2004, the EITF reached a consensus on the
application guidance for EITF 03-1, which provides a model for determining when
investments in certain debt and equity securities are considered other than
temporarily impaired. When an impairment is other-than-temporary, the investment
must be measured at fair value and the impairment loss recognized in earnings.
The recognition and measurement provisions of EITF 03-1, which were to be
effective for periods beginning after June 15, 2004, were delayed by the
issuance of FSP EITF 03-1-1 in September 2004. During the period of delay, the
Company will continue to evaluate its investments as required by existing
authoritative guidance.13
**METROPOLITAN EDISON COMPANY**

**CONSOLIDATED STATEMENTS OF INCOME**

**2004**
    
    **2003**
    
    **2002*****(In thousands)*****OPERATING REVENUES (Note 2(I))**
    
    $
    1,070,847
    
    $
    969,788
    
    $
    986,608**OPERATING EXPENSES AND TAXES:**Fuel and purchased power (Note 2(I))
    
    
    554,988
    
    
    491,346
    
    
    497,163Other operating costs (Note 2(I))
    
    
    190,401
    
    
    157,986
    
    
    155,137Provision for depreciation
    
    
    41,161
    
    
    44,160
    
    
    50,838Amortization of regulatory assets
    
    
    105,675
    
    
    97,784
    
    
    97,957General taxes
    
    
    70,457
    
    
    67,207
    
    
    66,795Income taxes
    
    
    21,968
    
    
    27,367
    
    
    27,447Total operating expenses and taxes
    
    
    984,650
    
    
    885,850
    
    
    895,337**OPERATING INCOME**
    
    
    86,197
    
    
    83,938
    
    
    91,271**OTHER INCOME (NET OF INCOME
      TAXES)**
    
    
    25,537
    
    
    21,782
    
    
    21,742**NET INTEREST CHARGES:**Interest on long-term debt
    
    
    40,630
    
    
    36,657
    
    
    40,774Allowance for borrowed funds used duringconstruction
    
    
    (278
    )
    
    (323
    )
    
    (470
    )Deferred interest
    
    
    --
    
    
    (1,187
    )
    
    ( 710
    )Other interest expense
    
    
    4,427
    
    
    5,841
    
    
    2,636Subsidiary's preferred stock dividend requirements
    
    
    --
    
    
    3,779
    
    
    7,559Net interest charges
    
    
    44,779
    
    
    44,767
    
    
    49,789**INCOME BEFORE CUMULATIVE EFFECT
    OF****ACCOUNTING CHANGE**
    
    
    66,955
    
    
    60,953
    
    
    63,224Cumulative effect of accounting change (net of incometaxes of $154,000) (Note 2(G))
    
    
    --
    
    
    217
    
    
    --**NET INCOME**
    
    $
    66,955
    
    $
    61,170
    
    $
    63,224
The accompanying Notes to Consolidated Financial Statements are
an integral part of these statements.
14**METROPOLITAN EDISON COMPANY**

**CONSOLIDATED BALANCE SHEETS**

**As of December 31,**
    **2004**
    
    **2003*****(In thousands)*****ASSETS****UTILITY PLANT:**In service
    $
    1,800,569
    
    $
    1,838,567Less-Accumulated provision for depreciation
    
    709,895
    
    
    772,1231,090,674
    
    
    1,066,444Construction work in progress
    
    21,735
    
    
    21,9801,112,409
    
    
    1,088,424**OTHER PROPERTY AND INVESTMENTS:**Nuclear plant decommissioning trusts
    
    216,951
    
    
    192,409Long-term notes receivable from associated companies
    
    10,453
    
    
    9,892Other
    
    34,767
    
    
    34,922262,171
    
    
    237,223**CURRENT ASSETS:**Cash and cash equivalents
    
    120
    
    
    121Notes receivable from associated companies
    
    18,769
    
    
    10,467Receivables-Customers (less accumulated provisions of $4,578,000 and
      $4,943,000
      respectively, for uncollectible accounts)
    
    119,858
    
    
    118,933Associated companies
    
    118,245
    
    
    45,934Other (less accumulated provisions of $68,000
      for uncollectible accounts in 2003)
    
    15,493
    
    
    22,750Prepayments and other
    
    11,057
    
    
    6,600283,542
    
    
    204,805**DEFERRED CHARGES:**Regulatory assets
    
    693,133
    
    
    1,028,432Goodwill
    
    869,585
    
    
    884,279Other
    
    24,438
    
    
    30,8241,587,156
    
    
    1,943,535$
    3,245,278
    
    $
    3,473,987**CAPITALIZATION AND LIABILITIES****CAPITALIZATION**(See Consolidated
      Statements of Capitalization):Common stockholder’s equity
    $
    1,285,419
    
    $
    1,292,667Long-term debt and other long-term obligations
    
    701,736
    
    
    636,3011,987,155
    
    
    1,928,968**CURRENT LIABILITIES:**Currently payable long-term debt
    
    30,435
    
    
    40,469Short-term borrowings (Note 10)-Associated companies
    
    80,090
    
    
    65,335Accounts payable-Associated companies
    
    88,879
    
    
    45,459Other
    
    26,097
    
    
    33,878Accrued taxes
    
    11,957
    
    
    8,762Accrued interest
    
    11,618
    
    
    11,848Other
    
    23,076
    
    
    22,162272,152
    
    
    227,913**NONCURRENT LIABILITIES:**Accumulated deferred income taxes
    
    305,389
    
    
    297,140Accumulated deferred investment tax credits
    
    10,868
    
    
    11,696Power purchase contract loss liability
    
    349,980
    
    
    584,340Nuclear fuel disposal costs
    
    38,408
    
    
    37,936Asset retirement obligation
    
    132,887
    
    
    210,178Retirement benefits
    
    82,218
    
    
    105,552Other
    
    66,221
    
    
    70,264985,971
    
    
    1,317,106**COMMITMENTS AND CONTINGENCIES**(Notes 5 and 11)$
    3,245,278
    
    $
    3,473,987


The accompanying Notes to Consolidated Financial Statements
are an integral part of these balance sheets.15**METROPOLITAN EDISON COMPANY**

**CONSOLIDATED STATEMENTS OF
CAPITALIZATION**

**As of December 31,**
    **2004**
    
    **2003********
    ***(Dollars in thousands, except per share
      amounts)*****COMMON
      STOCKHOLDER'S EQUITY:**Common stock,
      without par value, authorized 900,000 shares859,500
      shares outstanding
    $
    1,289,943
    
    $
    1,298,130Accumulated
      other comprehensive loss (Note 2(F))
    
    (43,490
    )
    
    (32,474
    )Retained
      earnings (Note 8(A))
    
    38,966
    
    
    27,011Total common
      stockholder's equity
    
    1,285,419
    
    
    1,292,667**LONG-TERM
      DEBT (Note 8(C)):**First
      mortgage bonds:6.340% due
      2004
    
    --
    
    
    40,0006.770% due
      2005
    
    30,000
    
    
    30,0006.360% due
      2006
    
    --
    
    
    17,0006.400% due
      2006
    
    --
    
    
    33,0006.000% due
      2008
    
    7,830
    
    
    8,2656.100% due
      2021
    
    28,500
    
    
    28,5005.950% due
      2027
    
    13,690
    
    
    13,690Total first
      mortgage bonds
    
    80,020
    
    
    170,455Secured
      notes:5.720% due
      2006
    
    --
    
    
    100,0005.930% due
      2007
    
    --
    
    
    50,0004.450% due
      2010
    
    --
    
    
    100,0004.950% due
      2013
    
    --
    
    
    150,000Total secured
      notes
    
    --
    
    
    400,000Unsecured
      notes:5.720% due
      2006
    
    100,000
    
    
    --5.930% due
      2007
    
    50,000
    
    
    --4.450% due
      2010
    
    100,000
    
    
    --4.950% due
      2013
    
    150,000
    
    
    --4.875% due
      2014
    
    250,000
    
    
    --7.690% due
      2039
    
    --
    
    
    5,9367.350% due
      2039
    
    --
    
    
    95,711Total
      unsecured notes
    
    650,000
    
    
    101,647Net
      unamortized premium on debt
    
    2,151
    
    
    4,668Long-term
      debt due within one year
    
    (30,435
    )
    
    (40,469
    )Total
      long-term debt
    
    701,736
    
    
    636,301**TOTAL
      CAPITALIZATION**
    $
    1,987,155
    
    $
    1,928,968


The accompanying Notes to Consolidated Financial Statements
are an integral part of these statements.16
**METROPOLITAN EDISON COMPANY**

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

**Accumulated****Common Stock**
    
    **Other****Comprehensive**
    
    **Number**
    
    **Carrying**
    
    **Comprehensive**
    
    **Retained****Income**
    
    **of Shares**
    
    **Value**
    
    **Income (Loss)**
    
    **Earnings***(Dollars in thousands)*Balance, January 1, 2002
    
    
    
    
    859,500
    
    $
    1,274,325
    
    $
    11
    
    $
    14,617Net income
    $
    63,224
    
    
    
    
    
    
    
    
    
    
    
    63,224Net unrealized gain on investment
    
    17
    
    
    
    
    
    
    
    
    17Net unrealized loss on derivative instruments
    
    (67
    )
    
    
    
    
    
    
    
    (67
    )Comprehensive income
    $
    63,174Cash dividends on common stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    (60,000
    )Purchase accounting fair value adjustment
    
    
    
    
    
    
    
    23,459Balance, December 31, 2002
    
    
    
    
    859,500
    
    
    1,297,784
    
    
    (39
    )
    
    17,841Net income
    $
    61,170
    
    
    
    
    
    
    
    
    
    
    
    61,170Net unrealized gain on investments
    
    2
    
    
    
    
    
    
    
    
    2Net unrealized gain on derivative instruments
    
    78
    
    
    
    
    
    
    
    
    78Minimum liability for unfunded retirement
      benefits, net of $(23,062,000) of
      income
      taxes
    
    (32,515
    )
    
    
    
    
    
    
    
    (32,515
    )Comprehensive income
    $
    28,735Cash dividends on common stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    (52,000
    )Purchase accounting fair value adjustment
    
    
    
    
    
    
    
    346Balance, December 31, 2003
    
    
    
    
    859,500
    
    
    1,298,130
    
    
    (32,474
    )
    
    27,011Net income
    $
    66,955
    
    
    
    
    
    
    
    
    
    
    
    66,955Net unrealized loss on investments
    
    (26
    )
    
    
    
    
    
    
    
    (26
    )Net unrealized loss on derivative
      instruments, net of $(1,279,000)
of
      income taxes
    
    (1,819
    )
    
    
    
    
    
    
    
    (1,819
    )Minimum liability for unfunded retirement
      benefits, net of $(6,502,000) of income
      taxes
    
    (9,171
    )
    
    
    
    
    
    
    
    (9,171
    )Comprehensive income
    $
    55,939Cash dividends on common stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    (55,000
    )Purchase accounting fair value adjustment
    
    
    
    
    
    
    
    (8,187
    )Balance, December 31, 2004
    
    
    
    
    859,500
    
    
    1,289,943
    
    
    (43,490
    )
    
    38,966


**CONSOLIDATED STATEMENTS OF PREFERRED
STOCK**

**Subject to**
      **Mandatory Redemption****Number**
    
    **Carrying****of Shares**
    
    **Value*****(Dollars in
  thousands)***Balance January 1, 2002
    
    4,000,000
    
    $
    92,200Amortization of fair market
      value adjustment
    
    
    
    
    209Balance, December 31, 2002
    
    4,000,000
    
    $
    92,409FIN 46 Deconsolidation7.35% Series
    
    (4,000,000
    )
    
    (92,618)Amortization of fair market
      value adjustment
    
    
    
    
    209Balance, December 31, 2003
    
    --
    
    
    --Balance, December 31, 2004
    
    --
    
    $
    --

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




17**METROPOLITAN EDISON COMPANY**

**CONSOLIDATED STATEMENTS OF CASH FLOWS**


**2004**
    
    **2003**
    
    **2002*****(In thousands)*****CASH FLOWS FROM OPERATING
      ACTIVITIES:**Net Income
    $
    66,955
    
    $
    61,170
    
    $
    63,224Adjustments to reconcile net income to net
      cash from operating activities:Provision for depreciation
    
    41,161
    
    
    44,160
    
    
    50,838Amortization of regulatory assets
    
    105,675
    
    
    97,784
    
    
    97,957Other amortization
    
    --
    
    
    --
    
    
    (2,528
    )Deferred costs recoverable as regulatory assets
    
    (65,981
    )
    
    (70,752
    )
    
    (86,314
    )Deferred income taxes and investment tax credits, net
    
    18,495
    
    
    45,832
    
    
    22,564Accrued retirement benefits obligations
    
    (186
    )
    
    (3,284
    )
    
    63Accrued compensation, net
    
    584
    
    
    5,531
    
    
    (2,491
    )Cumulative effect of accounting change (Note 2(G))
    
    --
    
    
    (371
    )
    
    --Pension trust contribution
    
    (38,823
    )
    
    --
    
    
    --Decrease (increase) in operating assets:Receivables
    
    (65,979
    )
    
    10,380
    
    
    (24,672
    )Prepayments and other current assets
    
    (4,457
    )
    
    3,131
    
    
    2,508Increase (decrease) in operating liabilities:Accounts payable
    
    35,639
    
    
    (20,988
    )
    
    (18,657
    )Accrued taxes
    
    3,195
    
    
    (7,334
    )
    
    9,059Accrued interest
    
    (230
    )
    
    (4,600
    )
    
    (1,020
    )Other
    
    (22,222
    )
    
    (28,171
    )
    
    (8,657
    )Net cash provided from operating activities
    
    73,826
    
    
    132,488
    
    
    101,874**CASH FLOWS FROM FINANCING
      ACTIVITIES:**New Financing-Long-term debt
    
    247,606
    
    
    247,696
    
    
    49,750Short-term borrowings, net
    
    14,755
    
    
    --
    
    
    16,288Redemptions and Repayments-Long-term debt
    
    (196,371
    )
    
    (260,466
    )
    
    (60,000
    )Short-term borrowings, net
    
    --
    
    
    (22,964
    )
    
    --Dividend Payments-Common stock
    
    (55,000
    )
    
    (52,000
    )
    
    (60,000
    )Net cash provided from (used for) financing activities
    
    10,990
    
    
    (87,734
    )
    
    (53,962
    )**CASH FLOWS FROM INVESTING
      ACTIVITIES:**Property additions
    
    (52,979
    )
    
    (43,558
    )
    
    (44,533
    )Contributions to decommissioning trusts
    
    (9,483
    )
    
    (9,483
    )
    
    (12,644
    )Loan payments to associated companies, net
    
    (8,863
    )
    
    (7,941
    )
    
    --Other
    
    (13,492
    )
    
    664
    
    
    (324
    )Net cash used for investing activities
    
    (84,817
    )
    
    (60,318
    )
    
    (57,501
    )Net decrease in cash and cash equivalents
    
    (1
    )
    
    (15,564
    )
    
    (9,589
    )Cash and cash equivalents at beginning of period
    
    121
    
    
    15,685
    
    
    25,274Cash and cash equivalents at end of period
    $
    120
    
    $
    121
    
    $
    15,685**SUPPLEMENTAL CASH FLOWS
    INFORMATION:**Cash Paid During the Year-Interest (net of amounts capitalized)
    $
    43,733
    
    $
    51,505
    
    $
    46,266Income taxes (refund)
    $
    33,693
    
    $
    (25,085
    )
    $
    34,385


The accompanying Notes to Consolidated Financial Statements
are an integral part of these statements.
18**METROPOLITAN EDISON COMPANY**

**CONSOLIDATED STATEMENTS OF TAXES**

**2004**
    
    **2003**
    
    **2002*****(In thousands)*****GENERAL TAXES:**State gross receipts *
    $
    58,900
    
    $
    53,462
    
    $
    56,043Real and personal property
    
    1,490
    
    
    2,510
    
    
    1,384Social security and unemployment
    
    3,800
    
    
    2,448
    
    
    1Other
    
    6,267
    
    
    8,787
    
    
    9,367Total general taxes
    $
    70,457
    
    $
    67,207
    
    $
    66,795**PROVISION FOR INCOME TAXES:**Currently payable-Federal
    $
    12,679
    
    $
    (3,435
    )
    $
    15,371State
    
    7,043
    
    
    1,763
    
    
    6,43719,722
    
    
    (1,672
    )
    
    21,808Deferred, net-Federal
    
    20,599
    
    
    38,863
    
    
    19,615State
    
    (1,276
    )
    
    7,791
    
    
    3,74119,323
    
    
    46,654
    
    
    23,356Investment tax credit amortization
    
    (828
    )
    
    (822
    )
    
    (792
    )Total provision for income taxes
    $
    38,217
    
    $
    44,160
    
    $
    44,372**INCOME STATEMENT CLASSIFICATION****OF PROVISION FOR INCOME TAXES:**Operating income
    $
    21,968
    
    $
    27,367
    
    $
    27,447Other income
    
    16,249
    
    
    16,639
    
    
    16,925Cumulative effect of accounting change
    
    --
    
    
    154
    
    
    --Total provision for income taxes
    $
    38,217
    
    $
    44,160
    
    $
    44,372**RECONCILIATION OF FEDERAL INCOME
    TAX****EXPENSE AT STATUTORY RATE TO
    TOTAL****PROVISION FOR INCOME TAXES:**Book income before provision for income taxes
    $
    105,172
    
    $
    105,330
    
    $
    107,596Federal income tax expense at statutory rate
    $
    36,810
    
    $
    36,866
    
    $
    37,659Increases (reductions) in taxes resulting from-Amortization of investment tax credits
    
    (828
    )
    
    (822
    )
    
    (792
    )Depreciation
    
    2,662
    
    
    1,736
    
    
    1,362State income tax, net of federal benefit
    
    3,749
    
    
    6,289
    
    
    6,107Other, net
    
    (4,176
    )
    
    91
    
    
    36Total provision for income taxes
    $
    38,217
    
    $
    44,160
    
    $
    44,372**ACCUMULATED DEFERRED INCOME TAXES
    AT****DECEMBER 31:**Property basis differences
    $
    257,880
    
    $
    250,779
    
    $
    217,351Nuclear decommissioning
    
    (4,755
    )
    
    (6,405
    )
    
    (4,247
    )Deferred sale and leaseback costs
    
    (11,149
    )
    
    (10,986
    )
    
    (11,366
    )Non-utility generation costs
    
    7,475
    
    
    2,287
    
    
    (4,832
    )Purchase accounting basis difference
    
    (642
    )
    
    (642
    )
    
    (642
    )Sale of generation assets
    
    (1,419
    )
    
    (1,419
    )
    
    (1,419
    )Regulatory transition charge
    
    95,056
    
    
    88,020
    
    
    88,315Customer receivables for future income taxes
    
    40,636
    
    
    46,010
    
    
    50,259Other comprehensive income
    
    (30,843
    )
    
    (23,062
    )
    
    --Employee benefits
    
    (5,289
    )
    
    (17,252
    )
    
    --Other
    
    (41,561
    )
    
    (30,190
    )
    
    (16,662
    )Net deferred income tax liability
    $
    305,389
    
    $
    297,140
    
    $
    316,757

* 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.


19**NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS**

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

The
consolidated financial statements include Met-Ed (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, JCP&L and Penelec.

The Company
follows GAAP and complies with the regulations, orders, policies and practices
prescribed by the SEC, PPUC 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. 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 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. 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.

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; andcan 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 PPUC 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.20Net regulatory
assets on the Consolidated Balance Sheets are comprised of the following:


**2004**
    
    **2003*****(In millions)***Regulatory transition costs
    
    $
    692
    
    $
    926Customer receivables for future income taxes
    
    
    90
    
    
    103Nuclear decommissioning costs
    
    
    (122
    )
    
    (26
    )Employee postretirement benefit costs
    
    
    16
    
    
    18Loss on reacquired debt
    
    
    17
    
    
    8Other
    
    
    --
    
    
    (1
    )Total
    
    **$**
    **693**
    
    **$**
    **1,028**


Regulatory
transition charges as of December 31, 2004 include $0.5 billion for the deferral
of above-market costs from power supplied by NUGs. These costs are being
recovered through CTC revenues. The regulatory asset for above-market NUG costs
and a corresponding liability are adjusted to fair value at the end of each
quarter.

*Accounting
for Generation Operations-*

The
application of SFAS 71 was discontinued in 1998 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
the operations for which the application of SFAS 71 was discontinued, were $13
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 Pennsylvania.
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 $120 million
(billed - $74 million and unbilled - $46 million) and $119 million (billed - $70
million and unbilled - $49 million) as of December 31, 2004 and 2003,
respectively.

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

As a result of
the Company's acquisition by FirstEnergy in 2001, 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 continues to be reflected at
original cost since such assets remain subject to rate regulation on a
historical cost basis. 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.

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 2.4% in 2004, 2.6% in 2003 and 3.0% in 2002.
The decrease in the composite depreciation rate reflects changes in the
depreciable plant base due to assets with higher depreciation rates being fully
depreciated since 2002.21**(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 evaluations 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
$870 million of goodwill. 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 its 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. As of December 31, 2004 and December 31,
2003, accumulated other comprehensive loss consisted of a minimum liability for
unfunded retirement benefits of $42 million and $33 million, respectively. As of
December 31, 2004 accumulated other comprehensive loss also consisted of
unrealized losses on derivative instrument hedges of $2 million.

**(G)** **CUMULATIVE
EFFECT OF ACCOUNTING CHANGE**

As a result of
adopting SFAS 143 in January 2003, asset retirement costs were recorded in the
amount of $186 million as part of the carrying amount of the related
long-lived asset, offset by accumulated depreciation of $186 million. The
ARO liability on the date of adoption was $198 million, including accumulated
accretion for the period from the date the liability was incurred to the date of
adoption. The remaining cumulative effect adjustment for unrecognized
depreciation and accretion, offset by the reduction in the existing
decommissioning liabilities and the reversal of accumulated estimated removal
costs for non-regulated generation assets, was a $371,000 increase to income,
$217,000 net of tax in the year ended December 31, 2003. If SFAS 143 had
been applied during 2002, the impact would not have been material to the
Company’s Consolidated Statements of Income.22
**(H)** **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 carryforward items are
recognized at the statutory income tax rates in effect when the liabilities are
expected to be paid. Deferred tax assets are recognized based on income tax
rates expected to be in effect when they are settled. 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.

**(I)** **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 corporate support services to the Company. The
Company also entered into sale and purchase transactions with affiliates
(JCP&L and Penelec) during 2002. Effective September 1, 2002, the
Company purchases a portion of its PLR responsibility from FES through a
wholesale power sale agreement. The primary affiliated companies transactions
are as follows:


**2004**
    
    **2003**
    
    **2002*****(In millions)*****Operating Revenues:**Wholesale sales-affiliated companies
    
    $
    --
    
    $
    --
    
    $
    19**Operating Expenses:**Power purchased from FES
    
    
    434
    
    
    277
    
    
    172Service Company support services
    
    
    46
    
    
    50
    
    
    68Power purchased from other affiliates
    
    
    --
    
    
    2
    
    
    10


FirstEnergy
does not bill directly or allocate any of its costs to any subsidiary company.
Costs are allocated to the Company from FESC, which is a subsidiary of
FirstEnergy and a "mutual service company" as defined in Rule 93 of the PUHCA.
The vast 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
$33 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 $39 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 $23 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.23Pension 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.24Unless
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
    
    $
    49
    
    $
    10
    
    $
    (59
    )
    $
    (59
    )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
    %25
**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


**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)
    
    $
    --
    
    $
    5
    
    $
    (11
    )
    $
    3
    
    $
    7
    
    $
    3


**Weighted-Average Assumptions
Used**
    
    
    
    **Other Benefits****to Determine Net Periodic Benefit
      Cost**
    
    **Pension 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:
26
**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
    )

Pursuant to
FSP 106-1 issued January 12, 2004, FirstEnergy began accounting for the
effects of the Medicare Act effective January 1, 2004 because of a plan
amendment during the quarter, which required remeasurement of the plan's
obligations. The plan amendment, which increases cost-sharing by employees and
retirees effective January 1, 2005, reduced 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 FSP106-2. The subsidy reduced the
Company's net periodic postretirement benefit costs by $4 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 $23 million. As prescribed by SFAS 87, the Company increased its
additional minimum liability by $16 million, offset by a charge to OCI. The
balance in AOCL of $42 million (net of $30 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 and
other long-term obligations as of December 31:


**2004**
    
    **2003****Carrying**
    
    **Fair**
    
    **Carrying**
    
    **Fair****Value**
    
    **Value**
    
    **Value**
    
    **Value*****(In millions)***Long-term debt
    
    $
    730
    
    $
    731
    
    $
    576
    
    $
    593Subordinated debentures to affiliated trusts
    
    
    --
    
    
    --
    
    
    96
    
    
    104$
    730
    
    $
    731
    
    $
    672
    
    $
    697


The fair
values of long-term debt and other long-term obligations reflect the present
value of the cash outflows relating to those securities based on the current
call price, the yield to maturity or the yield to call, as deemed appropriate at
the end of each respective year. The yields assumed were based on securities
with similar characteristics offered by corporations with credit ratings similar
to the Company’s ratings.
27Investments-

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
    
    $
    78
    
    $
    78
    
    $
    72
    
    $
    72-Corporate debt securities
    
    
    5
    
    
    5
    
    
    6
    
    
    683
    
    
    83
    
    
    78
    
    
    78Equity securities(1)
    
    
    137
    
    
    137
    
    
    117
    
    
    117$
    220
    
    $
    220
    
    $
    195
    
    $
    195

(1) Includes nuclear
decommissioning 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
decommissioning trust investments, which are classified as available-for-sale
securities. 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
    
    $
    80
    
    $
    3
    
    $
    --
    
    $
    83
    
    $
    74
    
    $
    4
    
    $
    --
    
    $
    78Equity securities
    
    
    113
    
    
    24
    
    
    3
    
    
    134
    
    
    75
    
    
    40
    
    
    1
    
    
    114$
    193
    
    $
    27
    
    $
    3
    
    $
    217
    
    $
    149
    
    $
    44
    
    $
    1
    
    $
    192


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
    
    $
    179
    
    $
    84
    
    $
    65Gross realized gains
    
    
    30
    
    
    2
    
    
    1Gross realized losses
    
    
    1
    
    
    1
    
    
    1Interest and dividend income
    
    
    6
    
    
    5
    
    
    5


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
    
    $
    10
    
    $
    --
    
    $
    6
    
    $
    --
    
    $
    16
    
    $
    --Equity securities
    
    
    21
    
    
    3
    
    
    1
    
    
    --
    
    
    22
    
    
    3$
    31
    
    $
    3
    
    $
    7
    
    $
    --
    
    
    38
    
    $
    3
28
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 recovery of amounts contributed to 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 $1.6 million, $1.6 million and $0.2
million for the years 2004, 2003 and 2002.

As of
December 31, 2004, the future minimum lease payments on the Company’s
Merrill Creek operating lease, net of reimbursements from sublessees, are: $1.5
million, $1.5 million, $1.5 million, $1.5 million and $1.9 million for the years
2005 through 2009, respectively, and $41.9 million for the years thereafter. The
Company’s Merrill Creek lease payments were offset against the actual net
divestiture proceeds received from the 1999 sales of its generating
assets.

**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 one 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 a variable interest in the remaining entity, which sells its output at
variable price that correlates to some extent with the operating costs of the
plant.

As required by
FIN 46R, the Company requests on a quarterly basis, the information necessary
from this entity to determine whether it is a VIE or whether the Company is the
primary beneficiary. The Company has been unable to obtain the requested
information, which 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 this entity 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 this entity during 2004, 2003 and
2002 were $54 million, $53 million and $53 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, FirstEnergy
completed implementation of all actions and initiatives related to enhancing
area reliability, improving voltage and reactive management, operator readiness
and training, and emergency response preparedness recommended for completion in
2004. Furthermore, FirstEnergy certified to NERC on June 30, 2004, with
minor exceptions noted, that FirstEnergy had completed the recommended
enhancements, policies, procedures and actions it had recommended be completed
by June 30, 2004. In addition, FirstEnergy requested, and NERC provided, a
technical assistance team of experts to assist in implementing and confirming
timely and successful completion of various initiatives. The NERC-assembled
independent verification team confirmed on July 14, 2004, that FirstEnergy
had implemented the NERC Recommended Actions to Prevent and Mitigate the Impacts
of Future Cascading Blackouts required to be completed by June 30, 2004, as
well as NERC recommendations contained in the Control Area Readiness Audit
Report required to be completed by summer 2004, and recommendations in the U.S.
- Canada Power System Outage Task Force Report directed toward FirstEnergy and
required to be completed by June 30, 2004, with minor exceptions noted by
FirstEnergy. On December 28, 2004, FirstEnergy submitted a follow-up to its
June 30, 2004 Certification and Report of Completion to NERC addressing the
minor exceptions, which are now essentially complete.

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.

In May 2004,
the PPUC issued an order approving the revised reliability benchmark and
standards, including revised benchmarks and standards for the Company. The
Company filed a Petition for Amendment of Benchmarks with the PPUC on
May 26, 2004 seeking amendment of the benchmarks and standards due to their
implementation of automated outage management systems following restructuring.
Evidentiary hearings have been scheduled for September 2005. FirstEnergy is
unable to predict the outcome of this proceeding.

On
January 16, 2004, the PPUC initiated a formal investigation of whether the
Company's "service reliability performance deteriorated to a point below the
level of service reliability that existed prior to restructuring" in
Pennsylvania. Hearings were held in early August 2004. On September 30,
2004, the Company filed a settlement agreement with the PPUC that addresses the
issues related to this investigation. As part of the settlement, the Company,
Penelec and Penn agreed to enhance service reliability, ongoing periodic
performance reporting and communications with customers and to collectively
maintain their current spending levels of at least $255 million annually on
combined capital and operation and maintenance expenditures for transmission and
distribution for the years 2005 through 2007. The settlement also outlines an
expedited remediation process to address any alleged non-compliance with terms
of the settlement and an expedited PPUC hearing process if remediation is
unsuccessful. On November 4, 2004, the PPUC accepted the recommendation of
the ALJ approving the settlement.

In June 2001,
the PPUC approved the Settlement Stipulation with all of the major parties in
the combined merger and rate relief proceedings which approved the
FirstEnergy/GPU merger and provided the Company PLR deferred accounting
treatment for energy costs. A February 2002 Commonwealth Court of Pennsylvania
decision affirmed the PPUC decision regarding approval of the merger, remanded
the issues of quantification and allocation of merger savings to the PPUC and
denied the PLR deferral accounting treatment. In October 2003, the PPUC issued
an order concluding that the Commonwealth Court reversed the PPUC’s
June 2001 order in its entirety. In accordance with the PPUC's direction,
the Company filed supplements to its tariffs which were effective October 2003
that reflected the CTC rates and shopping credits in effect prior to the
June 21, 2001 order.30
In response to
its October 8, 2003 petition, the PPUC denied the
Company's accounting request regarding the CTC rate/shopping credit swap by
requiring the Company to treat the stipulated CTC rates that were in effect from
January 1, 2002 on a retroactive basis. The Company subsequently filed with
the Commonwealth Court, on October 31, 2003, an Application for
Clarification with the judge, a Petition for Review of the PPUC's October 2
and October 16 Orders, and an application for reargument if the judge, in
his clarification order, indicates that the Company's Objection was intended to
be denied on the merits. The Reargument Brief before the Commonwealth Court was
filed January 28, 2005.

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

The Company
 purchases a portion of its PLR requirements  from FES through a
wholesale  power sale agreement. The PLR  sale is automatically 
extended for each successive calendar year unless any party elects to cancel the
agreement by November 1 of the preceding year. Under the terms of the
wholesale agreement, FES retains the supply obligation and the supply profit and
loss risk, for the portion of power supply requirements not self-supplied by the
Company under its NUG contracts and other power contracts with nonaffiliated
third party suppliers. This arrangement reduces the Company's exposure to high
wholesale power prices by providing power at a fixed price for its uncommitted
PLR energy costs during the term of the agreement with FES. The Company is
authorized to continue deferring differences between NUG contract costs and
current market prices.

On
January 12, 2005, the Company filed, before the PPUC, a request for
deferral of transmission-related costs beginning January 1, 2005 estimated
to be approximately $4 million per month. Various parties have intervened in
this case.

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

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

In general,
the Company’s FMB indentures restrict 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 $35.6
million, net of amounts restricted under the Company’s FMB indenture.

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

The Company’s
preferred stock authorization consists of 10 million shares without par value.
No preferred shares are currently outstanding.

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

*Subordinated
Debentures to Affiliated Trust*

The Company had formed a statutory business trust to sell
preferred securities and invest the gross proceeds in subordinated debentures.
Ownership of the Company's trust had been through a separate wholly owned
limited partnership. In this transaction, the trust had invested the gross
proceeds from the sale of its preferred securities in the preferred securities
of the limited partnership, which in turn invested those proceeds in the 7.35%
subordinated debentures of the Company. In June 2004, the Company extinguished
the subordinated debentures held by its affiliated trust and redeemed all of the
associated 7.35% preferred securities (aggregate value of $100 million).

*Other
Long-term Debt*

The Company’s
FMB indenture, which secures all of the Company’s FMBs, serve 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.
31Based 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 $6 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
    
    $ 302006
    
    
    1012007
    
    
    502008
    
    
    72009
    
    
    --


The Company’s
obligations to repay certain pollution control revenue bonds are secured by
several series of FMBs. Certain pollution control revenue bonds are entitled to
the benefit of noncancelable municipal bond insurance policies of
$42 million to pay principal of, or interest on, the pollution control
revenue bonds.

**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 $198 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
$260 million. The Company expects substantially all nuclear decommissioning
costs to be recoverable through regulated rates. Therefore, a regulatory
liability of $61 million was recognized upon adoption of SFAS 143. The ARO
includes the Company's obligation for nuclear decommissioning of TMI-2. 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 $217 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 $89 million.

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


**ARO Reconciliation**
    
    **2004**
    
    **2003*****(In millions)***Beginning balance as of January 1
    
    $
    210
    
    $
    198Accretion
    
    
    12
    
    
    12Revisions in estimated cash flows
    
    
    (89
    )
    
    --**Ending balance as of December 31**
    
    $
    133
    
    $
    210

32The 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
    $187Accretion
    11**Ending balance as of December 31**
    $198


**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 of $80 million from its
affiliates. The weighted average interest rates on short-term borrowings
outstanding at December 31, 2004 and 2003 were 2.0% and 1.7%,
respectively.

The Company
has, through a separate wholly owned subsidiary, a receivables financing
agreement under which the Company can borrow up to an aggregate of $80 million
at rates based on certain bank commercial paper and is required to pay an annual
facility fee of 0.30% on the entire finance limit. This financing agreement
expires on March 29, 2005. These receivables financing arrangements are
expected to be renewed prior to expiration.

**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 $0.4 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. The Company has accrued liabilities aggregating approximately
$26,000 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*

On
August 14,   2003, various states and parts of 
southern  Canada  experienced  widespread power  outages.
The outages  affected  approximately 1.4 million customers in
FirstEnergy's service area. On April 5, 2004, the U.S. - Canada Power
System Outage Task Force released its final report on the outages. In the final
report, the Task Force concluded, among other things, that the problems leading
to the outages began in FirstEnergy’s Ohio service area. Specifically, the final
report concludes, among other things, that the initiation of the August 14,
2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR
to assess and understand perceived inadequacies within the FirstEnergy system;
inadequate situational awareness of the developing conditions; and a perceived
failure to adequately manage tree growth in certain transmission rights of way.
The Task Force also concluded that there was a failure of the interconnected
grid's reliability organizations (MISO and PJM) to provide effective real-time
diagnostic support. The final report is publicly available through the
Department of Energy’s website (www.doe.gov). FirstEnergy believes that the
final report does not provide a complete and comprehensive picture of the
conditions that contributed to the August 14, 2003 power outages and that
it does not adequately address the underlying causes of the outages. FirstEnergy
remains convinced that the outages cannot be explained by events on any one
utility's system. The final report contains 46 "recommendations to prevent or
minimize the scope of future blackouts." Forty-five of those recommendations
relate to broad industry or policy matters while one, including subparts,
relates to activities the Task Force recommends be undertaken by FirstEnergy,
MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003
power 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 Regulatory Matters above).
FirstEnergy’s implementation of these recommendations included completion of the
Task Force recommendations that were directed toward FirstEnergy. As many of
these initiatives already were in process, 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 and the Company have 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 above.

**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.
34*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 Company’s 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):**

The following
summarizes certain consolidated operating results by quarter for 2004 and
2003.

**March 31,**
    
    **June 30,**
    
    **Sept. 30,**
    
    **Dec. 31,****Three Months Ended**
    
    **2004**
    
    **2004**
    
    **2004**
    
    **2004*****(In millions)***Operating Revenues
    
    $
    260.9
    
    $
    242.0
    
    $
    285.4
    
    $
    282.5Operating Expenses and Taxes
    
    
    237.6
    
    
    228.5
    
    
    265.1
    
    
    253.4Operating Income
    
    
    23.3
    
    
    13.5
    
    
    20.3
    
    
    29.1Other Income
    
    
    5.5
    
    
    6.2
    
    
    6.9
    
    
    7.0Net Interest Charges
    
    
    10.8
    
    
    13.0
    
    
    10.1
    
    
    10.9Net Income
    
    $
    18.0
    
    $
    6.7
    
    $
    17.1
    
    $
    25.2


**March 31,**
    
    **June 30,**
    
    **Sept. 30,**
    
    **Dec. 31,****Three Months Ended**
    
    **2003**
    
    **2003**
    
    **2003******
    
    **2003*****(In millions)***Operating Revenues
    
    $
    251.2
    
    $
    217.7
    
    $
    261.2
    
    $
    239.7Operating Expenses and Taxes
    
    
    227.2
    
    
    199.2
    
    
    242.0
    
    
    217.5Operating Income
    
    
    24.0
    
    
    18.5
    
    
    19.2
    
    
    22.2Other Income
    
    
    5.2
    
    
    5.3
    
    
    5.2
    
    
    6.1Net Interest Charges
    
    
    12.4
    
    
    11.0
    
    
    10.7
    
    
    10.7Income Before Cumulative Effect of
      Accounting Change
    
    
    16.8
    
    
    12.8
    
    
    13.7
    
    
    17.6Cumulative Effect of Accounting Change
      (Net of Income Taxes)
    
    
    0.2
    
    
    --
    
    
    --
    
    
    --Net Income
    
    $
    17.0
    
    $
    12.8
    
    $
    13.7
    
    $
    17.6





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