**PENNSYLVANIA
ELECTRIC COMPANY**
 
 **2004 ANNUAL
REPORT TO STOCKHOLDERS**
 
 
 
 Pennsylvania
Electric Company is a wholly owned electric utility operating subsidiary of
FirstEnergy Corp. It engages in the distribution and sale of electric energy in
an area of approximately 17,600 square miles in western Pennsylvania. It also
engages in the sale, purchase and interchange of electric energy with other
electric companies. The area it serves has a population of approximately 1.7
million. The Company is a lessee of the property of the Waverly Electric Light
& Power Company, which provides electric energy service in Waverly, New York
and vicinity.
 
 
 
 
 
 
 
 
 **Contents**
    
    **Page**Glossary of
      Terms
    
    i-iiManagement
      Reports
    
    1Report of
      Independent Registered Public Accounting Firm
    
    
    2Selected
      Financial Data
    
    
    3Management's
      Discussion and Analysis
    
    
    4-12Consolidated
      Statements of Income
    
    
    13Consolidated
      Balance Sheets
    
    
    14Consolidated
      Statements of Capitalization
    
    
    15Consolidated
      Statements of Common Stockholder's Equity
    
    
    16Consolidated
      Statements of Preferred Stock
    
    
    16Consolidated
      Statements of Cash Flows
    
    
    17Consolidated
      Statements of Taxes
    
    
    18Notes to
      Consolidated Financial Statements
    
    
    19-34
 
 
   
   **GLOSSARY OF
TERMS**
 
 The following
abbreviations and acronyms are used in this report to identify Pennsylvania
Electric Company and its affiliates:
 
 ATSI
    American
      Transmission Systems, Inc., owns and operates transmission
      facilitiesCompanies
    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 Company, an affiliated Pennsylvania electric
  utilityOE
    Ohio Edison
      Company, an affiliated Ohio electric utilityPenelec
    Pennsylvania
      Electric CompanyPenn
    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
      29
    APB Opinion
      No. 29, "Accounting for Accounting Research Bulletin"ARB
    Accounting
      Research BulletinARB
      43
    ARB No. 43,
      "Restatement and Revision of Accounting Research
  Bulletin"ARO
    Asset
      Retirement ObligationCTC
    Competitive
      Transition ChargeECAR
    East Central
      Area Reliability Coordination AgreementEITF
    Emerging
      Issues Task ForceEITF
      03-1
    EITF Issue
      No. 03-1, "The Meaning of Other-Than-Temporary and Its Application to
      Certain
      Investments"EITF
      03-16
    EITF Issue
      No. 03-16, "Accounting for Investments in Limited Liability
      Companies"EITF
      97-4
    EITF Issue
      No. 97-4 "Deregulation of the Pricing of Electricity - Issues Related to
      the Application
      of FASB
      Statements No. 71 and 101"FASB
    Financial
      Accounting Standards BoardFERC
    Federal
      Energy Regulatory CommissionFIN
      46R
    FASB
      Interpretation No. 46 (revised December 2003), "Consolidation of Variable
      Interest Entities"FMB
    First
      Mortgage BondsFSP EITF
      03-1-1
    FASB Staff
      Position No. EITF Issue 03-1-1, "Effective Date of Paragraphs 10-20 of
      EITF Issue
      No. 03-1, The
      Meaning of Other-Than-Temporary Impairment and Its Application to Certain
      Investments"FSP
      106-1
    FASB Staff
      Position No.106-1, "Accounting and Disclosure Requirements Related to the
      Medicare
      Prescription Drug, Improvement and Modernization Act of
    2003"FSP
      106-2
    FASB Staff
      Position No.106-2, "Accounting and Disclosure Requirements Related to the
      Medicare
      Prescription Drug, Improvement and Modernization Act of
    2003"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 ServiceMedicare
      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 ActS&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
      101
    SFAS No. 101,
      "Accounting for Discontinuation of Application of SFAS
  71"SFAS
      106
    SFAS No. 106,
      "Employers' Accounting for Postretirement Benefits Other Than
      Pensions"SFAS
      115
    SFAS No. 115,
      "Accounting for Certain Investments in Debt and Equity
      Securities"SFAS
      133
    SFAS No. 133,
      "Accounting for Derivative Instruments and Hedging
    Activities"SFAS
      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
Pennsylvania Electric Company:
 
 We have completed an
integrated audit of Pennsylvania Electric 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 Pennsylvania Electric 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
  **PENNSYLVANIA
ELECTRIC COMPANY**
 
 **SELECTED
FINANCIAL DATA**
 
 
 **Nov.
      7 -**
    
    
    **Jan.
      1 -****2004**
    
    **2003**
    
    **2002**
    
    **Dec.
      31, 2001**
    
    
    **Nov.
      6, 2001**
    
    **2000*****(Dollars
      in thousands)***Operating
      Revenues
    
    $
    1,036,070
    
    $
    974,857
    
    $
    1,027,102
    
    $
    140,062
    
    
    $
    834,548
    
    $
    901,881Operating
      Income
    
    $
    73,680
    
    $
    60,245
    
    $
    88,190
    
    $
    14,341
    
    
    $
    70,049
    
    $
    80,336Income Before
      Cumulative Effectof Accounting
      Change
    
    $
    36,030
    
    $
    20,237
    
    $
    50,910
    
    $
    10,795
    
    
    $
    23,718
    
    $
    39,250Net
      Income
    
    $
    36,030
    
    $
    21,333
    
    $
    50,910
    
    $
    10,795
    
    
    $
    23,718
    
    $
    39,250Total
      Assets
    
    $
    2,813,752
    
    $
    3,052,243
    
    $
    3,163,254
    
    $
    3,300,269
    
    
    
    
    
    $
    2,331,484**Capitalization
      as of December 31:**Common
      Stockholder’s Equity
    
    $
    1,305,015
    
    $
    1,297,332
    
    $
    1,353,704
    
    $
    1,306,576
    
    
    
    
    
    $
    469,837Company-Obligated
      TrustPreferred
      Securities
    
    
    --
    
    
    --
    
    
    92,214
    
    
    92,000
    
    
    
    
    
    
    100,000Long-Term
      Debt and Other Long-Term Obligations
    
    
    481,871
    
    
    438,764
    
    
    470,274
    
    
    472,400
    
    
    
    
    
    
    519,481Total
      Capitalization
    
    $
    1,786,886
    
    $
    1,736,096
    
    $
    1,916,192
    
    $
    1,870,976
    
    
    
    
    
    $
    1,089,318**Capitalization
      Ratios:**Common
      Stockholder’s Equity
    
    
    73.0
    %
    
    74.7
    %
    
    70.7
    %
    
    69.8
    %
    
    
    
    
    
    43.1
    %Company-Obligated
      TrustPreferred
      Securities
    
    
    --
    
    
    --
    
    
    4.8
    
    
    4.9
    
    
    
    
    
    
    9.2Long-Term
      Debt and Other Long-Term Obligations
    
    
    27.0
    
    
    25.3
    
    
    24.5
    
    
    25.3
    
    
    
    
    
    
    47.7Total
      Capitalization
    
    
    100.0
    %
    
    100.0
    %
    
    100.0
    %
    
    100.0
    %
    
    
    
    
    
    100.0
    %**Distribution
      Kilowatt-Hour Deliveries (Millions):**Residential
    
    
    4,249
    
    
    4,166
    
    
    4,196
    
    
    721
    
    
    
    3,264
    
    
    3,949Commercial
    
    
    4,792
    
    
    4,748
    
    
    4,753
    
    
    758
    
    
    
    3,733
    
    
    4,509Industrial
    
    
    4,589
    
    
    4,443
    
    
    4,336
    
    
    685
    
    
    
    3,658
    
    
    4,698Other
    
    
    39
    
    
    41
    
    
    42
    
    
    7
    
    
    
    34
    
    
    40Total
    
    
    13,669
    
    
    13,398
    
    
    13,327
    
    
    2,171
    
    
    
    10,689
    
    
    13,196**Customers
      Served:**Residential
    
    
    505,999
    
    
    503,738
    
    
    503,007
    
    
    502,901
    
    
    
    
    
    
    502,052Commercial
    
    
    78,519
    
    
    77,737
    
    
    77,125
    
    
    76,005
    
    
    
    
    
    
    74,282Industrial
    
    
    2,492
    
    
    2,545
    
    
    2,605
    
    
    2,652
    
    
    
    
    
    
    2,703Other
    
    
    1,056
    
    
    1,069
    
    
    1,081
    
    
    1,099
    
    
    
    
    
    
    1,110Total
    
    
    588,066
    
    
    585,089
    
    
    583,818
    
    
    582,657
    
    
    
    
    
    
    580,147
 
 
 
  3
  **PENNSYLVANIA
ELECTRIC 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 $36 million in 2004, compared to $21 million in 2003. The increase
in 2004 resulted from higher operating revenues and other income partially
offset by higher purchased power costs and other operating costs. Net income
decreased to $21 million or 58.1% in 2003 from $51 million in 2002. In 2003, net
income was lower due to lower operating revenues partially offset by reduced
purchased power costs, other operating costs and depreciation and amortization
charges.
 
 Operating revenues
increased by $61 million in 2004 compared to 2003, primarily due to higher
revenues from distribution deliveries and transmission revenues, which were
partially offset by lower retail generation revenues. Revenues from distribution
deliveries increased by $30 million due to higher unit prices and a 2.0%
increase in electricity throughput with increases in all customer sectors.
Kilowatt-hour deliveries increased to commercial and industrial customers
reflecting an improving economy in our service area. Retail generation revenues
decreased by $9 million due to lower composite prices. This decrease was
partially offset by a 3.1% increase in retail generation kilowatt-hour sales due
to generation customers returning to us after switching to alternative
suppliers. The lower retail generation prices were due to the PPUC Restructuring
Settlement order (see Note 7). There was minimal wholesale sales activity in
2004 and 2003. Transmission revenues increased $40 million in 2004 compared with
2003 due to an amended power supply agreement with FES, which resulted in our
recognizing certain transmission revenues that were previously attributed to FES
which also increased transmission expenses 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.
 
  4
  Operating revenues
decreased by $52 million in 2003 compared to 2002, primarily due to lower retail
generation revenues and wholesale sales revenues slightly offset by higher
distribution deliveries revenues. Total retail generation kilowatt-hour sales
decreased 2.5% ($22 million in operating revenues) as a result of decreases in
industrial sales (7.2%), residential sales (0.7%) and commercial sales (0.6%).
The decrease in industrial sales was primarily due to more industrial customers
being served by alternative suppliers. Wholesale sales revenues decreased by $32
million in 2003, primarily attributable to lower sales to non-affiliated
companies. Kilowatt-hour deliveries increased by 0.5% due to an increase in
industrial deliveries as a result of a slightly improving economy - partially
offset by lower deliveries to residential and commercial customers.
 
 Changes in electric
generation sales and distribution deliveries in 2004 and 2003 are summarized in
the following table:
 
 
 **Changes
      in Kilowatt-hour Sales**
    
    **2004**
    
    **2003*****Increase
      (Decrease)***Electric
      Generation:Retail
    
    
    3.1
    %
    
    (2.5
    )%Wholesale
    
    
    (100.0
    )%
    
    (99.5
    )%**Total
      Electric Retail Generation Sales**
    
    
    **3.1**
    **%**
    
    **(6.4**
    **)%**Distribution
      Deliveries:Residential
    
    
    2.0
    %
    
    (0.7
    )%Commercial
    
    
    0.9
    %
    
    (0.1
    )%Industrial
    
    
    3.3
    %
    
    2.5
    %**Total
      Distribution Deliveries**
    
    
    **2.0**
    **%**
    
    **0.5**
    **%**
 
 *Operating
Expenses and Taxes*
 
 Total operating
expenses and taxes increased by $48 million or 5.2% in 2004 and decreased $24
million or 2.6% in 2003, compared to the preceding year. Higher purchased power
costs, other operating costs and income taxes, accounted for the increase in
2004. In 2003, the decrease was due to lower purchased power costs,
depreciation, amortization and income taxes, offset in part by an increase in
general taxes. The following table presents changes from the prior year by
expense category.
 
 
 **Operating
      Expenses and Taxes - Changes**
    
    **2004**
    
    **2003****Increase
      (Decrease)**
    
    ***(In
      millions)***Purchase
      power costs
    
    $
    20
    
    $
    (6
    )Other
      operating costs
    
    
    19
    
    
    (2
    )Provision for
      depreciation
    
    
    (6
    )
    
    (6
    )Amortization
      of regulatory assets
    
    
    7
    
    
    (5
    )General
      taxes
    
    
    1
    
    
    2Income
      taxes
    
    
    7
    
    
    (7
    )**Total
      operating expenses and taxes**
    
    **$**
    **48**
    
    **$**
    **(24**
    **)**
 
 
 Purchased power
costs increased by $20 million or 3.7% in 2004, compared to the prior year. The
increase was due primarily to higher kilowatt-hours purchased to meet the
increased retail generation sales requirements. Purchased power costs decreased
by $6.0 million or 1.1% in 2003, compared to 2002, due primarily to a reduction
in kilowatt-hours purchased to support lower kilowatt-hour sales to retail and
wholesale customers.
 
 Other operating
costs increased by $19 million or 10.5% in 2004, compared to 2003. The increase
was primarily due to increased
transmission expenses, which were assumed in 2004 due to a change in the power
supply agreement with FES and to higher vegetation management costs. Other
operating costs were relatively unchanged in 2003 compared to 2002.
 
 Depreciation
charges decreased in 2004 primarily due to certain assets being fully
depreciated in 2003. Depreciation charges decreased in 2003 compared to 2002 due to
information system assets being fully depreciated in 2002 and higher cost of
removal charges in 2002 compared to 2003 **.** Amortization of
regulatory assets increased in 2004 compared to the prior year due to a higher
level of deferred NUG cost recovery. The decrease in 2003 from 2002 was due to
lower CTC revenue recovering deferred costs.
 
  5
  *Net Interest
Charges*
 
 Net interest
charges decreased $2 million in 2004 compared to the prior year, reflecting the
redemption of $100 million of 7.34% subordinated debentures in September 2004.
This decrease was partially offset by interest expense resulting from
intercompany loans through the money pool discussed below. We became a net
borrower in 2004 due to a required repayment to the NUG trust fund. In 2003, we
were a net lender due to a $106 million withdrawal from the NUG trust. Net
interest charges increased $3 million in 2003, compared to the prior year.
The increase was due to the change in deferred interest costs, offset in part by
lower preferred stock dividend requirements.
 
 *Cumulative
Effect of Accounting Change*
 
 Upon adoption of
SFAS 143 in the first quarter of 2003, we recorded an after-tax gain to net
income of $1.1 million. The cumulative effect adjustment for unrecognized
depreciation and accretion, offset by the reduction in the existing
decommissioning liabilities and ceasing the accounting practice of depreciating
non-regulated generation assets using a cost of removal component, was a $1.9
million increase to income, or $1.1 million net of income taxes.
 
 **Capital
Resources and Liquidity**
 
 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*
 
 There was no change
as of December 31, 2004 and December 31, 2003 in our cash and cash
equivalents of $36,000.
 
 *Cash Flows From
Operating Activities*
 
 Our net cash
provided from operating activities was $46 million in 2004, $16 million in 2003
and $39 million in 2002, summarized as follows:
 
 
 **Operating
      Cash Flows**
    
    **2004**
    
    **2003**
    
    **2002*****(In
      millions)***Cash earnings(1)
    
    $
    112
    
    $
    88
    
    $
    63Pension trust
      contribution(2)
    
    
    (30
    )
    
    --
    
    
    --Working
      capital and other
    
    
    (36
    )
    
    (72
    )
    
    (24
    )**Total**
    
    **$**
    **46**
    
    **$**
    **16**
    
    **$**
    **39**
 
 (1)  Cash earnings is a
non-GAAP measure (see reconciliation below).
 (2)  Pension trust
contribution net of $20 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.
 
 
 **Reconciliation
      of Cash Earnings**
    
    **2004**
    
    **2003**
    
    **2002*****(In
      millions)***Net Income
      (GAAP)
    
    $
    36
    
    $
    21
    
    $
    51Non-Cash
      Charges (Credits):Provision for
      depreciation
    
    
    47
    
    
    52
    
    
    59Amortization
      of regulatory assets
    
    
    50
    
    
    45
    
    
    49Deferred
      costs recoverable as regulatory assets
    
    
    (87
    )
    
    (80
    )
    
    (106
    )Deferred
      income taxes and investment tax credits
    
    
    58
    
    
    41
    
    
    11Cumulative
      effect of accounting change
    
    
    --
    
    
    (2
    )
    
    --Other
      non-cash expenses
    
    
    8
    
    
    11
    
    
    (1
    )**Cash
      earnings (Non-GAAP)**
    
    **$**
    **112**
    
    **$**
    **88**
    
    **$**
    **63**
 
  6
  Net cash provided
from operating activities increased $30 million in 2004 compared to 2003
resulting from increases of $36 million from working capital changes and $24
million in cash earnings, partially offset by a $30 million after-tax voluntary
pension contribution. The increase from working capital was principally due to
changes in accounts payable balances. The increase in cash earnings is described
under "Results of Operations". Net cash from operating activities decreased by
$23 million in 2003 compared to 2002 due to a $48 million decrease from changes
in working capital partially offset by a $25 million increase in cash earnings
which is described under "Results of Operations". The decrease from working
capital resulted from a $79 million change in accounts payable partially offset
by a $41 million change in receivables.
 
 *Cash Flows From
Financing Activities*
 
 Net cash provided
from financing activities of $76 million in 2004 compares to net cash of $49
million used in 2003. The net change reflects a $97 million increase in
borrowings and a $28 million decrease in common stock dividend payments to
FirstEnergy. The net decrease of $17 million in net cash used for financing
activities in 2003 compared to 2002 reflects a $24 million reduction in net debt
refinancing activity partially offset by a $7 million increase in common stock
dividend payments to FirstEnergy. The following table provides details regarding
new issues and redemptions during each year:
 
 
 **Securities
      Issued or Redeemed**
    
    **2004**
    
    **2003**
    
    **2002*****(In
      millions)***New
      Issues-  
      Unsecured notes
    
    $
    150
    
    $
    --
    
    $
    --Redemptions-  
      Unsecured notes
    
    
    229
    
    
    1
    
    
    50Short-term
      Borrowings, net (use)/source of cash
    
    
    163
    
    
    (12
    )
    
    13
 
 
 In March 2004, we
completed a receivables financing arrangement providing for borrowings of up to
$75 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. These receivables financing arrangements are expected to be
renewed prior to expiration.
 
 On
September 1, 2004, we redeemed at par $100 million principal amount of our
subordinated debentures in connection with the concurrent redemption at par of
$100 million principal amount of 7.34% Penelec Capital Trust Preferred
Securities.
 
 As of
December 31, 2004, we had approximately $241 million of short-term
indebtedness, compared to $78 million at the end of 2003. Penelec has obtained
authorization from the SEC to incur short-term debt of up to $250 million
(including the utility money pool). We will not issue FMB other than as
collateral for senior notes, since our senior note indentures prohibit (subject
to certain exceptions) us from issuing any debt which is senior to the senior
notes. As of December 31, 2004, we had the ability to issue $25 million of
additional senior notes based upon FMB collateral. We have no restrictions on
the issuance of preferred stock.
 
 We have the ability
to borrow from our regulated affiliates and FirstEnergy to meet our short-term
working capital requirements. FESC administers this money pool and tracks
surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving
a loan under the money pool agreements must repay the principal, together with
accrued interest, within 364 days of borrowing the funds. The rate of interest
is the same for each company receiving a loan from the pool and is based on the
average cost of funds available through the pool. The average interest rate for
borrowings under these arrangements in 2004 was 1.43%.
 
 Our access to
capital markets and costs of financing are dependent on the ratings of our
securities and that of FirstEnergy. The ratings outlook on all securities is
stable.
 
 
 **Ratings
      of Securities****Securities**
    
    **S&P**
    
    **Moody’s**
    
    **Fitch****FirstEnergy**
    
    
    Senior
      unsecured
    
    
    BB+
    
    
    Baa3
    
    
    BBB-**Penelec**
    
    
    Senior
      secured
    
    
    BBB
    
    
    Baa1
    
    
    BBB+Senior
      unsecured
    
    
    BBB-
    
    
    Baa2
    
    
    BBB
 
 
  7
  On December 10,
2004, S&P reaffirmed FirstEnergy's ‘BBB-' corporate credit rating and kept
the outlook stable. S&P noted that the stable outlook reflects FirstEnergy's
improving financial profile and cash flow certainty through 2006. S&P stated
that should the two refueling outages at the Davis-Besse and Perry nuclear
plants scheduled for the first quarter of 2005 be completed successfully without
any significant negative findings and delays, FirstEnergy's outlook would be
revised to positive. S&P also stated that a ratings upgrade in the next
several months did not seem likely, as remaining issues of concern to S&P,
primarily the outcome of environmental litigation and SEC investigations, are
not likely to be resolved in the short term.
 
 *Cash Flows From
Investing Activities*
 
 Cash used for
investing activities totaled $123 million in 2004 and cash provided from
investing activities totaled approximately $22 million in 2003. In both periods,
cash outflows for property additions were made to support the distribution of
electricity. In 2004, cash was used for a $51 million repayment to the NUG trust
fund, while in 2003 cash was provided from a $106 million withdrawal from the
NUG trust fund. Finally, net loan payments to associated companies resulted in
cash used of $8 million in 2004, whereas we received net payments of $2 million
in 2003.
 
 Our capital
spending for the period 2005-2007 is expected to be about $272 million for
property additions and improvements, of which approximately $89 million applies
to 2005.
 
 **Contractual
Obligations**
 
 As of
December 31, 2004, our estimated cash payments under existing contractual
obligations that we consider firm obligations were as follows:
 
 
 **Contractual
      Obligations**
    
    **Total**
    
    **2005**
    
    **2006-**
      **2007**
    
    **2008-**
      **2009**
    
    **Thereafter*****(In millions)***Long-term
      debt (2)
    
    $
    491
    
    $
    8
    
    $
    3
    
    $
    100
    
    $
    380Short-term
      borrowings
    
    
    241
    
    
    241
    
    
    --
    
    
    --
    
    
    --Purchases
      (1)
    
    
    3,437
    
    
    345
    
    
    887
    
    
    793
    
    
    1,412Total
    
    $
    4,169
    
    $
    594
    
    $
    890
    
    $
    893
    
    $
    1,792
 
 (1) Power
purchases under contracts with fixed or minimum quantities and approximate
timing
 (2)Amounts reflected do not include interest on long-term
debt.
 **Market Risk
Information**
 
 We use various
market risk sensitive instruments, including derivative contracts, primarily to
manage the risk of price fluctuations. Our Risk Policy Committee, comprised of
members of senior management, provides general management oversight to risk
management activities throughout our Company. They are responsible for promoting
the effective design and implementation of sound risk management programs. They
also oversee compliance with corporate risk management policies and established
risk management practices.
 
 *Commodity Price
Risk*
 
 We are exposed to
market  risk primarily due to fluctuations in electricity and natural
 gas prices. To manage  the volatility  relating to these
exposures, we use a variety of non-derivative and derivative instruments,
including options and futures contracts. The derivatives are used for hedging
purposes. As of December 31, 2004 and 2003, we had commodity derivative
contracts related to energy production that did not qualify for hedge treatment
under SFAS 133. The fair value of these contracts was $15 million as of
December 31, 2004 and 2003, and are included in non-current
assets.
 
 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 utilize these results in developing estimates of fair value for
financial reporting purposes and for internal management decision making.
Sources of information for the valuation of derivative contracts by year are
summarized in the following table:
 
  8
  
 **Source
      of Information - Fair Value by Contract Year****2005**
    
    **2006**
    
    **2007**
    
    **2008**
    
    **Thereafter**
    
    **Total*****(In
      millions)***Prices based
      on external sources(1)
    
    $
    4
    
    $
    3
    
    $
    --
    
    $
    --
    
    $
    --
    
    $
    7Prices based
      on models
    
    
    --
    
    
    --
    
    
    2
    
    
    2
    
    
    4
    
    
    8**Total**(2)
    
    **$**
    **4**
    
    **$**
    **3**
    
    **$**
    **2**
    
    **$**
    **2**
    
    **$**
    **4**
    
    **$**
    **15**
 
 (1)  Broker quote
sheets.
 (2)  Includes $15
million from an embedded option that is offset by a regulatory liability and
does not affect earnings.
 
 We perform
sensitivity analyses to estimate our exposure to the market risk of our
commodity position. A hypothetical 10% adverse shift in quoted market prices in
the near term on derivative instruments would not have had a material effect on
our consolidated financial position or cash flows as of December 31, 2004.
 
 *Interest Rate
Risk*
 
 Our exposure to
fluctuations in market interest rates is reduced since our debt has fixed
interest rates.
 
 **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
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    146
    
    **$**
    **146**
    
    **$**
    **146**Average
      interest rate
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    4.3
    %
    
    4.3
    %LiabilitiesLong-term
      Debt and Other
      Long-term
      Obligations:Fixed
      rate
    
    $
    8
    
    
    
    
    $
    3
    
    
    
    
    $
    100
    
    $
    380
    
    **$**
    **491**
    
    **$**
    **521**Average
      interest rate
    
    
    7.5
    %
    
    
    
    
    6.1
    %
    
    
    
    
    6.1
    %
    
    6.0
    %
    
    6.0
    %Short-term
      Borrowings
    
    
    241
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    **$**
    **241**
    
    **$**
    **241**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 $60 million and $54 million at December 31,
2004 and 2003, respectively. A hypothetical 10% decrease in prices quoted by
stock exchanges would result in a $6 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 our regulatory plan.
Our regulatory assets totaled $200 million and $497 million as of
December 31, 2004 and December 31, 2003,
respectively.
  9
  *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.
 
 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. We accrue environmental liabilities only when we can
conclude that it is probable that we have an obligation for such costs and can
reasonably determine the amount of such costs. Unasserted claims are reflected
in our determination of environmental liabilities and are accrued in the period
that they are both probable and reasonably estimable.
 
 *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 and in Note 11(C) to the consolidated financial statements.
 
 **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 its 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 $888 million.
 
 *Regulatory
Accounting*
 
 We are subject to
regulation that sets the prices (rates) we are permitted to charge our customers
based on the costs that the regulatory agencies determine we are permitted to
recover. At times, regulators permit the future recovery through rates of costs
that would be currently charged to expense by an unregulated company. This
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.
  10
  *Revenue
Recognition*
 
 We follow the
accrual method of accounting for revenues, recognizing revenue for electricity
that has been delivered to customers but not yet billed through the end of the
accounting period. The determination of electricity sales to individual
customers is based on meter readings, which occur on a systematic basis
throughout the month. At the end of each month, electricity delivered to
customers since the last meter reading is estimated and a corresponding accrual
for unbilled sales is recognized. The determination of unbilled sales requires
management to make estimates regarding electricity available for retail load,
transmission and distribution line losses, demand by customer class,
weather-related impacts, prices in effect for each customer class and
electricity provided by alternative suppliers.
 
 *Pension and
Other Postretirement Benefits Accounting*
 
 Our reported costs
of providing non-contributory defined pension benefits and postemployment
benefits other than pensions are dependent upon numerous factors resulting from
actual plan experience and certain assumptions.
 
 Pension and OPEB
costs are affected by employee demographics (including age, compensation levels,
and employment periods), the level of contributions we make to the plans, and
earnings on plan assets. Such factors may be further affected by business
combinations, which impact employee demographics, plan experience and other
factors. Pension and OPEB costs are also affected by changes to key assumptions,
including anticipated rates of return on plan assets, the discount rates and
health care trend rates used in determining the projected benefit obligations
for pension and OPEB costs.
 
 In accordance with
SFAS 87, changes in pension and OPEB obligations associated with these factors
may not be immediately recognized as costs on the income statement, but
generally are recognized in future years over the remaining average service
period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes
due to the long-term nature of pension and OPEB obligations and the varying
market conditions likely to occur over long periods of time. As such,
significant portions of pension and OPEB costs recorded in any period may not
reflect the actual level of cash benefits provided to plan participants and are
significantly influenced by assumptions about future market conditions and plan
participants' experience.
 
 In selecting an
assumed discount rate, we consider currently available rates of return on
high-quality fixed income investments expected to be available during the period
to maturity of the pension and other postretirement benefit obligations. Due to
recent declines in corporate bond yields and interest rates in general, we
reduced the assumed discount rate as of December 31, 2004 to 6.00% from
6.25% and 6.75% used as of December 31, 2003 and 2002, respectively.
 
 Our assumed rate of
return on pension plan assets considers historical market returns and economic
forecasts for the types of investments held by 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 $50 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 $32 million. As
prescribed by SFAS 87, we increased our additional minimum liability by $18
million, offset by a charge to OCI. The balance in AOCL of $52 million (net of
$37 million in deferred taxes) will reverse in future periods to the extent the
fair value of trust assets exceeds the accumulated benefit obligation.
 
 Health care cost
trends have significantly increased and will affect future OPEB costs. The 2004
and 2005 composite health care trend rate assumptions are approximately 10%-12%
and 9%-11%, respectively, gradually decreasing to 5% in later years. In
determining our trend rate assumptions, we included the specific provisions of
our health care plans, the demographics and utilization rates of plan
participants, actual cost increases experienced in its health care plans, and
projections of future medical trend rates.
 
  11
  *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.
 
 *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.
 
 **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, we will continue to evaluate our investments
as required by existing authoritative guidance.
 
 
 
   12
   **PENNSYLVANIA
ELECTRIC COMPANY**
 
 **CONSOLIDATED
STATEMENTS OF INCOME**
 
 
 **2004**
    
    **2003**
    
    **2002*****(In
      thousands)*****OPERATING
      REVENUES (Note 2(I))**
    $
    1,036,070
    
    $
    974,857
    
    $
    1,027,102**OPERATING
      EXPENSES AND TAXES:**Fuel and
      purchased power (Note 2(I))
    
    570,369
    
    
    550,155
    
    
    556,133Other
      operating costs (Note 2(I))
    
    197,069
    
    
    178,393
    
    
    180,161Provision for
      depreciation
    
    47,104
    
    
    51,754
    
    
    58,913Amortization
      of regulatory assets
    
    50,403
    
    
    44,908
    
    
    48,990General
      taxes
    
    68,132
    
    
    66,999
    
    
    65,301Income
      taxes
    
    29,313
    
    
    22,403
    
    
    29,414Total
      operating expenses and taxes
    
    962,390
    
    
    914,612
    
    
    938,912**OPERATING
      INCOME**
    
    73,680
    
    
    60,245
    
    
    88,190**OTHER
      INCOME**
    
    2,314
    
    
    1,885
    
    
    1,742**NET
      INTEREST CHARGES:**Interest on
      long-term debt
    
    30,029
    
    
    29,565
    
    
    31,758Allowance for
      borrowed funds used during construction
    
    (248
    )
    
    (320
    )
    
    (52
    )Deferred
      interest
    
    190
    
    
    4,553
    
    
    (3,299
    )Other
      interest expense
    
    9,993
    
    
    4,318
    
    
    3,061Subsidiary's
      preferred stock dividend requirements
    
    --
    
    
    3,777
    
    
    7,554Net interest
      charges
    
    39,964
    
    
    41,893
    
    
    39,022**INCOME
      BEFORE CUMULATIVE****EFFECT
      OF ACCOUNTING CHANGE**
    
    36,030
    
    
    20,237
    
    
    50,910Cumulative
      effect of accounting change (net of
      income taxes
      of $777,000) (Note 2(G))
    
    --
    
    
    1,096
    
    
    --**NET
      INCOME**
    $
    36,030
    
    $
    21,333
    
    $
    50,910
 
 
 The accompanying
Notes to Consolidated Financial Statements are an integral part of these
statements.
 
  13
  **PENNSYLVANIA
ELECTRIC COMPANY**
 
 **CONSOLIDATED
BALANCE SHEETS**
 
 **As of
      December 31,**
    
    **2004**
    
    **2003*****(In
      thousands)*****ASSETS****UTILITY
      PLANT:**In
      service
    
    $
    1,981,846
    
    $
    1,966,624Less-Accumulated
      provision for depreciation
    
    
    776,904
    
    
    785,7151,204,942
    
    
    1,180,909Construction
      work in progress
    
    
    22,816
    
    
    29,0631,227,758
    
    
    1,209,972**OTHER
      PROPERTY AND INVESTMENTS:**Nuclear plant
      decommissioning trusts
    
    
    109,620
    
    
    102,673Non-utility
      generation trusts
    
    
    95,991
    
    
    43,864Long-term
      notes receivable from associated companies
    
    
    14,001
    
    
    13,794Other
    
    
    18,746
    
    
    19,635238,358
    
    
    179,966**CURRENT
      ASSETS:**Cash and cash
      equivalents
    
    
    36
    
    
    36Receivables-Customers
      (less accumulated provisions of $4,712,000 and $5,833,000,
      respectively,
      for uncollectible accounts)
    
    
    121,112
    
    
    124,462Associated
      companies
    
    
    97,528
    
    
    88,598Other (less
      accumulated provisions of $4,000 and $399,000,
      respectively,
      for uncollectible accounts)
    
    
    12,778
    
    
    15,767Notes
      receivable from associated companies
    
    
    7,352
    
    
    --Prepayments
      and other
    
    
    7,198
    
    
    2,511246,004
    
    
    231,374**DEFERRED
      CHARGES:**Goodwill
    
    
    888,011
    
    
    898,547Regulatory
      assets
    
    
    200,173
    
    
    497,219Accumulated
      deferred income tax benefits
    
    
    --
    
    
    16,642Other
    
    
    13,448
    
    
    18,5231,101,632
    
    
    1,430,931$
    2,813,752
    
    $
    3,052,243**CAPITALIZATION
      AND LIABILITIES****CAPITALIZATION**(See
      Consolidated Statements of Capitalization):Common
      stockholder’s equity
    
    $
    1,305,015
    
    $
    1,297,332Long-term
      debt and other long-term obligations
    
    
    481,871
    
    
    438,7641,786,886
    
    
    1,736,096**CURRENT
      LIABILITIES:**Currently
      payable long-term debt
    
    
    8,248
    
    
    125,762Short-term
      borrowings (Note 10)-Associated
      companies
    
    
    241,496
    
    
    78,510Accounts
      payable-Associated
      companies
    
    
    56,154
    
    
    55,831Other
    
    
    25,960
    
    
    40,192Accrued
      taxes
    
    
    7,999
    
    
    8,705Accrued
      interest
    
    
    9,695
    
    
    12,694Other
    
    
    23,750
    
    
    21,764373,302
    
    
    343,458**NONCURRENT
      LIABILITIES:**Power
      purchase contract loss liability
    
    
    382,548
    
    
    670,482Asset
      retirement obligation
    
    
    66,443
    
    
    105,089Accumulated
      deferred income taxes
    
    
    37,318
    
    
    --Retirement
      benefits
    
    
    118,247
    
    
    145,081Other
    
    
    49,008
    
    
    52,037653,564
    
    
    972,689**COMMITMENTS
      AND CONTINGENCIES**(Notes 5 and
      11)$
    2,813,752
    
    $
    3,052,243
 
 The accompanying
Notes to Consolidated Financial Statements are an integral part of these balance
sheets.
  14
  **PENNSYLVANIA
ELECTRIC COMPANY**
 
 **CONSOLIDATED
STATEMENTS OF CAPITALIZATION**
 
 
 **As of
      December 31,**
    
    **2004**
    
    **2003*****(Dollars
      in thousands, except per share amounts)*****COMMON
      STOCKHOLDER'S EQUITY:**Common stock,
      par value $20 per share, authorized 5,400,000 shares
      5,290,596
      shares outstanding
    
    $
    105,812
    
    $
    105,812Other paid-in
      capital
    
    
    1,205,948
    
    
    1,215,667Accumulated
      other comprehensive loss (Note 2 (F))
    
    
    (52,813
    )
    
    (42,185
    )Retained
      earnings (Note 8(A))
    
    
    46,068
    
    
    18,038Total common
      stockholder's equity
    
    
    1,305,015
    
    
    1,297,332**LONG-TERM
      DEBT AND OTHER LONG-TERM OBLIGATIONS (Note 8
(C)):**First
      mortgage bonds:6.125% due
      2007
    
    
    3,495
    
    
    3,7005.350% due
      2010
    
    
    12,310
    
    
    12,3105.350% due
      2010
    
    
    12,000
    
    
    12,0005.800% due
      2020
    
    
    20,000
    
    
    20,0006.050% due
      2025
    
    
    25,000
    
    
    25,000Total first
      mortgage bonds
    
    
    72,805
    
    
    73,010Unsecured
      notes:5.750% due
      2004
    
    
    --
    
    
    125,0007.500% due
      2005
    
    
    8,000
    
    
    8,0006.125% due
      2009
    
    
    100,000
    
    
    100,0007.770% due
      2010
    
    
    35,000
    
    
    35,0005.125% due
      2014
    
    
    150,000
    
    
    --6.625% due
      2019
    
    
    125,000
    
    
    125,0007.340% due
      2039
    
    
    --
    
    
    95,5207.690% due
      2039
    
    
    --
    
    
    2,968Total
      unsecured notes
    
    
    418,000
    
    
    491,488Capital lease
      obligations (Note 5)
    
    
    43
    
    
    540Net
      unamortized discount on debt
    
    
    (729
    )
    
    (512
    )Long-term
      debt due within one year
    
    
    (8,248
    )
    
    (125,762
    )Total
      long-term debt and other long-term obligations
    
    
    481,871
    
    
    438,764**TOTAL
      CAPITALIZATION**
    
    $
    1,786,886
    
    $
    1,736,096
 
 
 The accompanying
Notes to Consolidated Financial Statements are an integral part of these
statements.
  15
  **PENNSYLVANIA
ELECTRIC COMPANY**
 
 **CONSOLIDATED
STATEMENTS OF COMMON STOCKHOLDER’S EQUITY**
 
 **Accumulated****Common
      Stock**
    
    **Other**
    
    **Other****Comprehensive**
    
    **Number**
    
    **Par**
    
    **Paid-In**
    
    **Comprehensive**
    
    **Retained****Income**
    
    **of
      Shares**
    
    **Value**
    
    **Capital**
    
    **Income
      (Loss)**
    
    **Earnings*****(Dollars
      in thousands)***Balance,
      January 1, 2002
    
    
    
    5,290,596
    
    $105,812
    
    $1,188,190
    
    $1,779
    
    $10,795Net
      income
    
    $
    50,910
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    50,910Net
      unrealized gain on investments
    
    
    5
    
    
    
    
    
    
    
    
    
    
    
    5Net
      unrealized loss on derivative instruments
    
    
    (1,853
    )
    
    
    
    
    
    
    
    
    
    
    (1,853
    )Comprehensive
      income
    
    $
    49,062Cash
      dividends on common stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (29,000
    )Purchase
      accounting fair value adjustment
    
    
    
    
    
    
    
    
    
    
    
    27,066Balance,
      December 31, 2002
    
    
    
    
    
    5,290,596
    
    
    105,812
    
    
    1,215,256
    
    
    (69
    )
    
    32,705Net
      income
    
    $
    21,333
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    21,333Net unrealized
      gain on derivative instruments
    
    
    72
    
    
    
    
    
    
    
    
    
    
    
    72Minimum
      liability for unfunded retirement benefits,
      net of
      $(29,908,000) of income taxes
    
    
    (42,188
    )
    
    
    
    
    
    
    
    
    
    
    (42,188
    )Comprehensive
      loss
    
    $
    (20,783
    )Cash dividends
      on common stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (36,000
    )Purchase
      accounting fair value adjustment
    
    
    
    
    
    
    
    
    
    
    
    411Balance,
      December 31, 2003
    
    
    
    
    
    5,290,596
    
    
    105,812
    
    
    1,215,667
    
    
    (42,185
    )
    
    18,038Net
      income
    
    $
    36,030
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    36,030Net unrealized
      loss on investments
    
    
    (2
    )
    
    
    
    
    
    
    
    
    
    
    (2
    )Net unrealized
      loss on derivative instruments, net
      of $(249,000)
      of income taxes
    
    
    (353
    )
    
    
    
    
    
    
    
    
    
    
    (353
    )Minimum
      liability for unfunded retirement benefits,
      net of
      $(7,298,000) of income taxes(10,273
    )
    
    
    
    
    
    
    
    
    
    
    (10,273
    )Comprehensive
      loss
    
    $
    25,402Cash dividends
      on common stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (8,000
    )Purchase
      accounting fair value adjustment
    
    
    
    
    
    
    
    
    
    
    
    (9,719
    )Balance,
      December 31, 2004
    
    
    
    
    
    5,290,596
    
    $
    105,812
    
    $
    1,205,948
    
    $
    (52,813
    )
    $
    46,068
 
 
 
 
 **CONSOLIDATED
STATEMENTS OF PREFERRED STOCK**
 
 **Subject
      to**
      **Mandatory
      Redemption****Number**
    
    **Carrying****of
      Shares**
    
    **Value*****(Dollars
      in thousands)***Balance,
      January 1, 2002
    
    
    4,000,000
    
    $
    92,000Amortization
      of fair market
      value
      adjustment
    
    
    
    
    
    214Balance,
      December 31, 2002
    
    
    4,000,000
    
    
    92,214FIN
      46 Deconsolidation7.34%
      Series
    
    
    (4,000,000
    )
    
    (92,428
    )Amortization
      of fair market
      value
      adjustment
    
    
    
    
    
    214Balance,
      December 31, 2003
    
    
    --
    
    
    --Balance,
      December 31, 2004
    
    
    --
    
    $
    --
 
 
 The accompanying
Notes to Consolidated Financial Statements are an integral part of these
statements.
 
 
   16
   **PENNSYLVANIA
ELECTRIC COMPANY**
 
 **CONSOLIDATED
STATEMENTS OF CASH FLOWS**
 
 **2004**
    
    **2003**
    
    **2002*****(In
      thousands)*****CASH
      FLOWS FROM OPERATING ACTIVITIES:**Net
      Income
    
    $
    36,030
    
    $
    21,333
    
    $
    50,910Adjustments
      to reconcile net income to net cash
      from
      operating activities:Provision for
      depreciation
    
    
    47,104
    
    
    51,754
    
    
    58,913Amortization
      of regulatory assets
    
    
    50,403
    
    
    44,908
    
    
    48,990Deferred
      costs recoverable as regulatory assets
    
    
    (87,379
    )
    
    (80,126
    )
    
    (105,380
    )Deferred
      income taxes and investment tax credits, net
    
    
    77,375
    
    
    40,889
    
    
    10,861Accrued
      retirement benefit obligations
    
    
    5,822
    
    
    2,727
    
    
    --Accrued
      compensation, net
    
    
    3,226
    
    
    7,956
    
    
    (1,275
    )Cumulative
      effect of accounting change (Note 2(G))
    
    
    --
    
    
    (1,873
    )
    
    --Pension trust
      contribution
    
    
    (50,281
    )
    
    --
    
    
    --Decrease
      (Increase) in operating assets:Receivables
    
    
    (2,591
    )
    
    13,052
    
    
    (27,509
    )Prepayments
      and other current assets
    
    
    (4,687
    )
    
    41
    
    
    6,054Increase
      (Decrease) in operating liabilities:Accounts
      payable
    
    
    (13,909
    )
    
    (84,700
    )
    
    (5,514
    )Accrued
      taxes
    
    
    (705
    )
    
    (4,215
    )
    
    (7,984
    )Accrued
      interest
    
    
    (2,999
    )
    
    --
    
    
    411Other
    
    
    (11,116
    )
    
    4,230
    
    
    10,835Net cash
      provided from operating activities
    
    
    46,293
    
    
    15,976
    
    
    39,312**CASH
      FLOWS FROM FINANCING ACTIVITIES:**New
      Financing-Long-term
      debt
    
    
    150,000
    
    
    --
    
    
    --Short-term
      borrowings, net
    
    
    162,986
    
    
    --
    
    
    12,804Redemptions
      and Repayments-Long-term
      debt
    
    
    (228,670
    )
    
    (812
    )
    
    (49,973
    )Short-term
      borrowings, net
    
    
    --
    
    
    (11,917
    )
    
    --Dividend
      Payments-Common
      stock
    
    
    (8,000
    )
    
    (36,000
    )
    
    (29,000
    )Net cash
      provided from (used for) financing activities
    
    
    76,316
    
    
    (48,729
    )
    
    (66,169
    )**CASH
      FLOWS FROM INVESTING ACTIVITIES:**Property
      additions
    
    
    (51,801
    )
    
    (44,657
    )
    
    (50,671
    )Non-utility
      generation trusts withdrawals (contributions)
    
    
    (50,614
    )
    
    66,327
    
    
    49,044Loan
      repayments from (payments to) associated
      companies,
      net
    
    
    (7,559
    )
    
    1,721
    
    
    --Other,
      net
    
    
    (12,635
    )
    
    (912
    )
    
    (239
    )Net cash
      provided from (used for) investing activities
    
    
    (122,609
    )
    
    22,479
    
    
    (1,866
    )Net change in
      cash and cash equivalents
    
    
    --
    
    
    (10,274
    )
    
    (28,723
    )Cash and cash
      equivalents at beginning of period
    
    
    36
    
    
    10,310
    
    
    39,033Cash and cash
      equivalents at end of period
    
    $
    36
    
    $
    36
    
    $
    10,310**SUPPLEMENTAL
      CASH FLOWS INFORMATION:**Cash Paid
      During the Year-Interest (net
      of amounts capitalized)
    
    $
    40,765
    
    $
    37,497
    
    $
    32,695Income taxes
      (refund)
    
    $
    (36,434
    )
    $
    10,695
    
    $
    43,613
 
 The accompanying
Notes to Consolidated Financial Statements are an integral part of these
statements.
 
  17
  **PENNSYLVANIA
ELECTRIC COMPANY**
 
 **CONSOLIDATED
STATEMENTS OF TAXES**
 
 
 **2004**
    
    **2003**
    
    **2002*****(In
      thousands)*****GENERAL
      TAXES:**State gross
      receipts*
    
    $
    55,390
    
    $
    53,716
    
    $
    55,505Other
    
    
    12,742
    
    
    13,283
    
    
    9,796Total general
      taxes
    
    $
    68,132
    
    $
    66,999
    
    $
    65,301**PROVISION
      FOR INCOME TAXES:**Currently
      payable-Federal
    
    $
    (38,759
    )
    $
    (15,968
    )
    $
    17,554State
    
    
    (8,615
    )
    
    692
    
    
    5,833(47,374
    )
    
    (15,276
    )
    
    23,387Deferred,
      net-Federal
    
    
    64,435
    
    
    35,136
    
    
    10,600State
    
    
    13,959
    
    
    6,741
    
    
    1,29378,394
    
    
    41,877
    
    
    11,893Investment
      tax credit amortization
    
    
    (1,019
    )
    
    (988
    )
    
    (1,032
    )Total
      provision for income taxes
    
    $
    30,001
    
    $
    25,613
    
    $
    34,248**INCOME
      STATEMENT CLASSIFICATION****OF
      PROVISION FOR INCOME TAXES:**Operating
      income
    
    $
    29,313
    
    $
    22,403
    
    $
    29,414Other
      income
    
    
    688
    
    
    2,433
    
    
    4,834Cumulative
      effect of accounting change
    
    
    --
    
    
    777
    
    
    --Total
      provision for income taxes
    
    $
    30,001
    
    $
    25,613
    
    $
    34,248**RECONCILIATION
      OF FEDERAL INCOME TAX****EXPENSE
      AT STATUTORY RATE TO TOTAL****PROVISION
      FOR INCOME TAXES:**Book income
      before provision for income taxes
    
    $
    66,031
    
    $
    46,946
    
    $
    85,158Federal
      income tax expense at statutory rate
    
    $
    23,111
    
    $
    16,431
    
    $
    29,805Increases
      (reductions) in taxes resulting from-Amortization
      of investment tax credits
    
    
    (1,019
    )
    
    (988
    )
    
    (1,032
    )Depreciation
    
    
    1,649
    
    
    2,655
    
    
    1,591State income
      tax, net of federal benefit
    
    
    3,474
    
    
    4,831
    
    
    4,702Other,
      net
    
    
    2,786
    
    
    2,684
    
    
    (818
    )Total
      provision for income taxes
    
    $
    30,001
    
    $
    25,613
    
    $
    34,248**ACCUMULATED
      DEFERRED INCOME TAXES AT****DECEMBER
      31:**Property
      basis differences
    
    $
    294,220
    
    $
    291,752
    
    $
    242,192Nuclear
      decommissioning
    
    
    (40,349
    )
    
    (39,869
    )
    
    (41,665
    )Non-utility
      generation costs
    
    
    (181,649
    )
    
    (223,350
    )
    
    (223,644
    )Purchase
      accounting basis difference
    
    
    (762
    )
    
    (762
    )
    
    (762
    )Sale of
      generation assets
    
    
    7,495
    
    
    7,495
    
    
    7,495Customer
      receivables for future income taxes
    
    
    52,063
    
    
    55,817
    
    
    52,793Other
      comprehensive income
    
    
    (37,455
    )
    
    (29,908
    )
    
    --Employee
      benefits
    
    
    (20,397
    )
    
    (42,368
    )
    
    --Other
    
    
    (35,848
    )
    
    (35,449
    )
    
    (37,926
    )Net deferred
      income tax liability (asset)
    
    $
    37,318
    
    $
    (16,642
    )
    $
    (1,517
    )
 
 
 * 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.
 
 
 
   18
   **NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS**
 
 **1.**
    **ORGANIZATION
      AND BASIS OF PRESENTATION:**
 
 The consolidated
financial statements include Penelec (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 subsidiaries, including OE, CEI, TE,
ATSI, JCP&L and Met-Ed.
 
 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.  E xpenses (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; and·
    can be
      charged to and collected from customers.
 
 An enterprise
meeting all of these criteria capitalizes costs that would otherwise be charged
to expense if the rate actions of its regulator make it probable that those
costs will be recovered in future revenue. SFAS 71 is applied only to the parts
of the business that meet the above criteria. If a portion of the business
applying SFAS 71 no longer meets those requirements, previously recorded
regulatory assets are removed from the balance sheet in accordance with the
guidance in SFAS 101.
 
 *Regulatory
Assets-*
 
 The Company
recognizes, as regulatory assets, costs which the FERC and the 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.
 
  19
  Net regulatory
assets on the Consolidated Balance Sheets are comprised of the
following:
 
 **2004**
    
    **2003*****(In
      millions)***Regulatory
      transition costs
    
    $
    114
    
    $
    366Customer
      receivables for future income taxes
    
    
    119
    
    
    128Nuclear
      decommissioning costs
    
    
    (47
    )
    
    (1
    )Loss on
      reacquired debt and other
    
    
    14
    
    
    4**Total**
    
    **$**
    **200**
    
    **$**
    **497**
 
 Regulatory
transition charges as of December 31, 2004 consist primarily of deferred charges
for 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 1999 with respect to the Company's generation
operations. The Company subsequently divested substantially all of its
generating assets. The SEC's interpretive guidance and EITF 97-4 regarding asset
impairment measurement, provides that any supplemental regulated cash flows such
as a CTC should be excluded from the cash flows of assets in a portion of the
business not subject to regulatory accounting practices. If those assets are
impaired, a regulatory asset should be established if the costs are recoverable
through regulatory cash flows.
 
 **(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 $121 million (billed -
$76 million and unbilled - $45 million) and $124 million (billed - $73 million
and unbilled - $51 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 2.5% in 2004, 2.7% 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.
 
  20
  **(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 $888 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, accumulated other
comprehensive loss consisted of a minimum liability for unfunded retirement
benefits of $52 million and unrealized losses on derivative instrument hedges of
$1 million. As of December 31, 2003, accumulated other comprehensive loss
consisted of a minimum liability for unfunded retirement benefits of $42
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 $93 million as part of the carrying amount of the related long-lived
asset, offset by accumulated depreciation of $93 million. The ARO liability on
the date of adoption was $99 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 $1.9 million increase to income ($1.1 million 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.
 
  21
  **(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 Met-Ed) 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
    
    $
    --
    
    $
    --
    
    $
    9**Operating
      Expenses:**Power
      purchased from FES
    
    
    404
    
    
    307
    
    
    188Service
      Company support services
    
    
    45
    
    
    55
    
    
    82Power
      purchased from other affiliates
    
    
    --
    
    
    5
    
    
    10
 
 
 FirstEnergy does
not bill directly or allocate any of its costs to any subsidiary company. Costs
are allocated to the Company from FESC, a subsidiary of FirstEnergy and a
"mutual service company" as defined in Rule 93 of 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 total for direct payroll, number of employees, asset balances,
revenues, number of customers, other factors and specific departmental charge
ratios. It is management’s belief that allocation methods utilized are
reasonable. Intercompany transactions with FirstEnergy and its other
subsidiaries are generally settled under commercial terms within thirty days,
except for a net $45 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 (Company's share was $50 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 $30 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.
 
  22
  Pension and OPEB
costs are affected by employee demographics (including age, compensation levels,
and employment periods), the level of contributions made to the plans, and
earnings on plan assets. Such factors may be further affected by business
combinations, which impact employee demographics, plan experience and other
factors. Pension and OPEB costs may also be affected by changes in key
assumptions, including anticipated rates of return on plan assets, the discount
rates and health care trend rates used in determining the projected benefit
obligations and pension and OPEB costs. FirstEnergy uses a December 31
measurement date for the majority of its plans.
 
 Unless otherwise
indicated, the following tables provide information applicable to FirstEnergy’s
pension and OPEB plans.
 
 **Obligations
      and Funded Status**
    
    **Pension
      Benefits**
    
    **Other
      Benefits****As of
      December 31**
    
    **2004**
    
    **2003**
    
    **2004**
    
    **2003*****(In
      millions)*****Change
      in benefit obligation**Benefit
      obligation as of January 1
    
    $
    4,162
    
    $
    3,866
    
    $
    2,368
    
    $
    2,077Service
      cost
    
    
    77
    
    
    66
    
    
    36
    
    
    43Interest
      cost
    
    
    252
    
    
    253
    
    
    112
    
    
    136Plan
      participants’ contributions
    
    
    --
    
    
    --
    
    
    14
    
    
    6Plan
      amendments
    
    
    --
    
    
    --
    
    
    (281
    )
    
    (123
    )Actuarial
      (gain) loss
    
    
    134
    
    
    222
    
    
    (211
    )
    
    323Benefits
      paid
    
    
    (261
    )
    
    (245
    )
    
    (108
    )
    
    (94
    )Benefit
      obligation as of December 31
    
    $
    4,364
    
    $
    4,162
    
    $
    1,930
    
    $
    2,368**Change
      in fair value of plan assets**Fair value of
      plan assets as of January 1
    
    $
    3,315
    
    $
    2,889
    
    $
    537
    
    $
    473Actual return
      on plan assets
    
    
    415
    
    
    671
    
    
    57
    
    
    88Company
      contribution
    
    
    500
    
    
    --
    
    
    64
    
    
    68Plan
      participants’ contribution
    
    
    --
    
    
    --
    
    
    14
    
    
    2Benefits
      paid
    
    
    (261
    )
    
    (245
    )
    
    (108
    )
    
    (94
    )Fair value of
      plan assets as of December 31
    
    $
    3,969
    
    $
    3,315
    
    $
    564
    
    $
    537**Funded
      status**
    
    $
    (395
    )
    $
    (847
    )
    $
    (1,366
    )
    $
    (1,831
    )Unrecognized
      net actuarial loss
    
    
    885
    
    
    919
    
    
    730
    
    
    994Unrecognized
      prior service cost (benefit)
    
    
    63
    
    
    72
    
    
    (378
    )
    
    (221
    )Unrecognized
      net transition obligation
    
    
    --
    
    
    --
    
    
    --
    
    
    83Net asset
      (liability) recognized
    
    $
    553
    
    $
    144
    
    $
    (1,014
    )
    $
    (975
    )**Amounts
      Recognized in the**
      **Consolidated
      Balance Sheets**
      **As of
      December 31**Accrued
      benefit cost
    
    $
    (14
    )
    $
    (438
    )
    $
    (1,014
    )
    $
    (975
    )Intangible
      assets
    
    
    63
    
    
    72
    
    
    --
    
    
    --Accumulated
      other comprehensive loss
    
    
    504
    
    
    510
    
    
    --
    
    
    --Net amount
      recognized
    
    $
    553
    
    $
    144
    
    $
    (1,014
    )
    $
    (975
    )Company's
      share of net amount recognized
    
    $
    64
    
    $
    14
    
    $
    (92
    )
    $
    (86
    )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
    %
 
  23
  **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)
    
    $--
    
    $7
    
    $(16)
    
    $3
    
    $10
    
    $3**Weighted-Average
      Assumptions Used****to
      Determine Net Periodic Benefit Cost**
    
    **Pension
      Benefits**
    
    **Other
      Benefits****for
      Years Ended December 31**
    
    **2004**
    
    **2003**
    
    **2002**
    
    **2004**
    
    **2003**
    
    **2002**Discount
      rate
    
    
    6.25
    %
    
    6.75
    %
    
    7.25
    %
    
    6.25
    %
    
    6.75
    %
    
    7.25
    %Expected
      long-term return on plan assets
    
    
    9.00
    %
    
    9.00
    %
    
    10.25
    %
    
    9.00
    %
    
    9.00
    %
    
    10.25
    %Rate of
      compensation increase
    
    
    3.50
    %
    
    3.50
    %
    
    4.00
    %
 
 
 In selecting an
assumed discount rate, FirstEnergy considers currently available rates of return
on high-quality fixed income investments expected to be available during the
period to maturity of the pension and other postretirement benefit obligations.
The assumed rate of return on pension plan assets considers historical market
returns and economic forecasts for the types of investments held by the
Company's pension trusts. The long-term rate of return is developed considering
the portfolio’s asset allocation strategy.
 
 FirstEnergy employs
a total return investment approach whereby a mix of equities and fixed income
investments are used to maximize the long-term return of plan assets for a
prudent level of risk. Risk tolerance is established through careful
consideration of plan liabilities, plan funded status, and corporate financial
condition. The investment portfolio contains a diversified blend of equity and
fixed-income investments. Furthermore, equity investments are diversified across
U.S. and non-U.S. stocks, as well as growth, value, and small and large
capitalizations. Other assets such as real estate are used to enhance long-term
returns while improving portfolio diversification. Derivatives may be used to
gain market exposure in an efficient and timely manner; however, derivatives are
not used to leverage the portfolio beyond the market value of the underlying
investments. Investment risk is measured and monitored on a continuing basis
through periodic investment portfolio reviews, annual liability measurements,
and periodic asset/liability studies.
 
 
 **Assumed
      Health Care Cost Trend Rates****As of
      December 31**
    
    **2004**
    
    **2003**Health care
      cost trend rate assumed for next
      year
      (pre/post-Medicare)
    
    
    9%-11
    %
    
    10%-12
    %Rate to which
      the cost trend rate is assumed to
      decline (the
      ultimate trend rate)
    
    
    5
    %
    
    5
    %Year that the
      rate reaches the ultimate trend
      rate
      (pre/post-Medicare)
    
    
    2009-2011
    
    
    2009-2011
 
 
 Assumed health care
cost trend rates have a significant effect on the amounts reported for the
health care plans. A one-percentage-point change in assumed health care cost
trend rates would have the following effects:
  24
  
 **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 FSP 106-2. The subsidy reduced the Company's
net periodic postretirement benefit costs by $5 million during
2004.
 
 As a result of its
voluntary contribution and the increased market value of pension plan assets,
the Company reduced its accrued benefit cost as of December 31, 2004 by $32
million. As prescribed by SFAS 87, the Company increased its additional minimum
liability by $18 million, offset by a charge to OCI. The balance in AOCL of $52
million (net of $37 million in deferred taxes) will reverse in future periods to
the extent the fair value of trust assets exceeds the accumulated benefit
obligation.
 
 Taking into account
estimated employee future service, FirstEnergy expects to make the following
benefit payments from plan assets:
 
 **Pension
      Benefits**
    
    **Other
      Benefits*****(In
      millions)***2005
    
    $
    228
    
    $
    1112006
    
    
    228
    
    
    1062007
    
    
    236
    
    
    1092008
    
    
    247
    
    
    1122009
    
    
    264
    
    
    115Years 2010 -
      2014
    
    
    1,531
    
    
    627
 
 
 **4.**  **FAIR VALUE
OF FINANCIAL INSTRUMENTS:**
 
 *Long-term Debt
and Other Long-term Obligations-*
 
 All borrowings with
initial maturities of less than one year are defined as financial instruments
under GAAP and are reported on the Consolidated Balance Sheets at cost, which
approximates their fair market value. The following table provides the
approximate fair value and related carrying amounts of long-term debt and other
long-term obligations as of December 31:
 
 **2004**
    
    **2003****Carrying**
    
    **Fair**
    
    **Carrying**
    
    **Fair****Value**
    
    **Value**
    
    **Value**
    
    **Value*****(In
      millions)***Long-term
      debt
    
    $
    491
    
    $
    521
    
    $
    468
    
    $
    508Subordinated
      debentures to affiliated trusts
    
    
    --
    
    
    --
    
    
    96
    
    
    104$
    491
    
    $
    521
    
    $
    564
    
    $
    612
 
 
  25
  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.
 
 *Investments-*
 
 The carrying
amounts of cash and cash equivalents approximate fair value due to the
short-term nature of these investments. The following table provides the
approximate fair value and related carrying amounts of investments other than
cash and cash equivalents as of December 31:
 
 
 **2004**
    
    **2003****Carrying**
    
    **Fair**
    
    **Carrying**
    
    **Fair****Value**
    
    **Value**
    
    **Value**
    
    **Value*****(In
      millions)***Debt
      securities:(1)-Government
      obligations
    
    $
    146
    
    $
    146
    
    $
    92
    
    $
    92-Corporate
      debt securities
    
    
    --
    
    
    --
    
    
    1
    
    
    1146
    
    
    146
    
    
    93
    
    
    93Equity
      securities(1)
    
    
    62
    
    
    62
    
    
    56
    
    
    56$
    208
    
    $
    208
    
    $
    149
    
    $
    149
 
 (1)  Includes nuclear
decommissioning and NUG trust investments.
 
 
 The fair value of
investments other than cash and cash equivalents represent cost (which
approximates fair value) or the present value of the cash inflows based on the
yield to maturity. The yields assumed were based on financial instruments with
similar characteristics and terms.
 
 Investments other
than cash and cash equivalents include held-to-maturity securities and
available-for-sale securities. Decommissioning trust investments are classified
as available-for-sale. The Company has no securities held for trading purposes.
The following table summarizes the amortized cost basis, gross unrealized gains
and losses and fair values for decommissioning trust investments as of
December 31:
 
 
 **2004**
    
    **2003****Cost**
    
    **Unrealized**
    
    **Unrealized**
    
    **Fair**
    
    **Cost**
    
    **Unrealized**
    
    **Unrealized**
    
    **Fair****Basis**
    
    **Gains**
    
    **Losses**
    
    **Value**
    
    **Basis**
    
    **Gains**
    
    **Losses**
    
    **Value*****(In
      millions)***Debt
      securities
    
    $
    49
    
    $
    1
    
    $
    --
    
    $
    50
    
    $
    47
    
    $
    2
    
    $
    --
    
    $
    49Equity
      securities
    
    
    55
    
    
    7
    
    
    2
    
    
    60
    
    
    36
    
    
    18
    
    
    --
    
    
    54$
    104
    
    $
    8
    
    $
    2
    
    $
    110
    
    $
    83
    
    $
    20
    
    $
    --
    
    $
    103
 
 
 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
    
    $
    102
    
    $
    41
    
    $
    24Gross
      realized gains
    
    
    18
    
    
    1
    
    
    --Gross
      realized losses
    
    
    --
    
    
    --
    
    
    --Interest and
      dividend income
    
    
    3
    
    
    3
    
    
    3
 
 
  26
  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
    
    $
    8
    
    $
    --
    
    $
    4
    
    $
    --
    
    $
    12
    
    $
    --Equity
      securities
    
    
    13
    
    
    2
    
    
    --
    
    
    --
    
    
    13
    
    
    2$
    21
    
    $
    2
    
    $
    4
    
    $
    --
    
    $
    25
    
    $
    2
 
 
 The Company
periodically evaluates the securities held by its nuclear decommissioning trusts
for other-than-temporary impairment. The Company considers the length of time
and the extent to which the security's fair value has been less than its cost
basis and other factors to determine whether an impairment is other than
temporary. The 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 leases are charged to operating
expenses on the Consolidated Statements of Income. The Company has a capital
lease for a building that expires in 2005. In 2004, total rentals related to
this capital lease were $0.5 million. In each of 2003 and 2002, total rentals
related to this capital lease were $0.7 million, comprised of an interest
element of $0.1 million and other costs of $0.6 million.
 
 As of
December 31, 2004, the future minimum lease payments on the Company’s
capital lease discussed above are $40,000 for the year 2005.
 
 **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 two of these entities, the Company has no variable
interests in the entities or the entities are governmental or not-for-profit
organizations not within the scope of FIN 46R. The Company may hold variable
interests in the remaining two entities, which sell their output at variable
prices that correlate to some extent with the operating costs of the
plants.
 
 As required by FIN
46R, the Company requests on a quarterly basis, the information necessary from
these entities to determine whether they are VIEs or whether the Company is the
primary beneficiary. The Company has been unable to obtain the requested
information, which was deemed by the requested entity to be proprietary. As
such, the Company applied the scope exception that exempts enterprises unable to
obtain the necessary information to evaluate entities under FIN 46R. The maximum
exposure to loss from these entities results from increases in the variable
pricing component under the contract terms and cannot be determined without the
requested data. The purchased power costs from these entities during 2004, 2003
and 2002 were $27 million, $27 million and $24 million,
respectively.
 
  27
  **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
completed subsequent to 2004 and will continue to periodically assess the
FERC-ordered Reliability Study recommendations for forecasted 2009 system
conditions, recognizing revised load forecasts and other changing system
conditions which may impact the recommendations. Thus far, implementation of the
recommendations has not required, nor is expected to require, substantial
investment in new, or material upgrades, to existing equipment. FirstEnergy
notes, however, that FERC or other applicable government agencies and
reliability coordinators may take a different view as to recommended
enhancements or may recommend additional enhancements in the future that could
require additional, material expenditures. Finally, the PUCO is continuing to
review the FirstEnergy filing that addressed upgrades to control room computer
hardware and software and enhancements to the training of control room
operators, before determining the next steps, if any, in the proceeding.
 
 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, Met-Ed and Penn
agreed to enhance service reliability, ongoing periodic performance reporting
and communications with customers and to collectively maintain their current
spending levels of at least $255 million annually on combined capital and
operation and maintenance expenditures for transmission and distribution for the
years 2005 through 2007. The settlement also outlines an expedited remediation
process to address any alleged non-compliance with terms of the settlement and
an expedited PPUC hearing process if remediation is unsuccessful. O n November 4,
2004, the PPUC accepted the recommendation of the ALJ approving the
settlement.
 
 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 issue 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 their tariffs which were effective
October 2003 that reflected the CTC rates and shopping credits in effect prior
to the June 21, 2001 order.
 
  28
  In response to its
October 8, 2003 petition, the PPUC approved June 30, 2004 as the date
for the Company's NUG trust fund refunds and denied its 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 $36.0
million, net of amounts restricted under the Company’s FMB
indentures.
 
 **(B)**
    **PREFERRED
      STOCK-**
 
 The Company’s
preferred stock authorization consists of 11.435 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 7.34% subordinated debentures of the Company. On
September 1, 2004, the Company extinguished the subordinated debentures
held by its affiliated trust and redeemed all of the associated 7.34% 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.
 
  29
  Based on the amount
of bonds authenticated by the Trustee through December 31, 2004, the
Company’s annual sinking fund requirements for all bonds issued under the
mortgage amount to approximately $1 million. The Company expects to fulfill its
sinking fund obligation by providing bondable property additions to the
Trustee.
 
 Sinking fund
requirements for FMB and maturing long-term debt for the next five years
are:
 
 
 ***(In
      millions)***2005
    
    $
      82006
    
    --2007
    
    32008
    
    
    --2009
    
    
    100
 
 
 The Company’s
obligations to repay certain pollution control revenue bonds are secured by
several series of FMB. Certain pollution control revenue bonds are entitled to
the benefit of noncancelable municipal bond insurance policies of
$69 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 $99.1 million, including accumulated accretion for the
period from the date the liability was incurred to the date of adoption. As of
December 31, 2002, the Company recognized decommissioning liabilities of
$129.9 million. The Company expects substantially all nuclear decommissioning
costs to be recoverable through regulated rates. Therefore, a regulatory
liability of $30.8 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 $110 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 $44 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
    
    $
    105
    
    $
    99Accretion
    
    
    5
    
    
    6Revisions in
      estimated cash flows
    
    
    (44
    )
    
    --**Ending
      balance as of December 31**
    
    $
    66
    
    $
    105
 
 
  30
  The following table
provides the year-end balance of the ARO for 2002, as if SFAS 143 had been
adopted on January 1, 2002.
 **Adjusted
      ARO Reconciliation**
    
    **2002*****(In
      millions)***Beginning
      balance as of January 1
    
    $
    93Accretion
    
    
    6**Ending
      balance as of December 31**
    
    $
    99
 
  
 
 **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 $241.5 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 a
receivables financing agreement under which the Company can borrow up to an
aggregate of $75 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 $0.2 million for incidents at
any covered nuclear facility occurring during a policy year which are in excess
of accumulated funds available to the insurer for paying losses.
 
 The Company intends
to maintain insurance against nuclear risks as described above as long as it is
available. To the extent that property damage, decontamination, decommissioning,
repair and replacement costs and other such costs arising from a nuclear
incident at TMI-2 exceed the policy limits of the insurance in effect with
respect to that plant, to the extent a nuclear incident is determined not to be
covered by the Company’s insurance policies, or to the extent such insurance
becomes unavailable in the future, the Company would remain at risk for such
costs.
 
 **(B)**
    **ENVIRONMENTAL
      MATTERS-**
 
 The Company has
been named as a PRP at waste disposal sites which may require cleanup under the
Comprehensive Environmental Response, Compensation and Liability Act of 1980.
Allegations of disposal of hazardous substances at historical sites and the
liability involved are often unsubstantiated and subject to dispute; however,
federal law provides that all PRPs for a particular site are liable on a joint
and several basis. 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.
 
  31
  **(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*
 
 Various lawsuits,
claims (including claims for asbestos exposure) and proceedings related to the
Company's normal business operations are 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.
 
  32
  *SFAS 151,
      "Inventory Costs - an amendment of ARB No. 43, Chapter
    4"*
 
 In November 2004,
the FASB issued this statement to clarify the accounting for abnormal amounts of
idle facility expense, freight, handling costs and wasted material (spoilage).
Previous guidance stated that in some circumstances these costs may be "so
abnormal" that they would require treatment as current period costs. SFAS 151
requires abnormal amounts for these items to always be recorded as current
period costs. In addition, this Statement requires that allocation of fixed
production overheads to the cost of conversion be based on the normal capacity
of the production facilities. The provisions of this statement are effective for
inventory costs incurred by the Company after June 30, 2005. The Company is
currently evaluating this standard but does not expect it to have a material
impact on the financial statements.
 
 *EITF Issue No.
03-1, "The Meaning of Other-Than-Temporary Impairment and its Application to
Certain Investments"*
 
 In March 2004,
the EITF reached a consensus on the application guidance for 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.
 
 *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 Penelec 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." The Company 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.
 
  33
  **14.**  **SUMMARY OF
QUARTERLY FINANCIAL DATA (UNAUDITED):**
 
 The following
summarizes certain consolidated operating results by quarter for 2004 and 2003:
 
 **Three
      Months Ended**
    
    **March
      31, 2004**
    
    **June
      30, 2004**
    
    **September
      30, 2004**
    
    **December
      31, 2004*****(In
      millions)***Operating
      Revenues
    
    $
    256.4
    
    $
    242.2
    
    $
    254.3
    
    $
    283.1Operating
      Expenses and Taxes
    
    
    240.9
    
    
    229.3
    
    
    226.9
    
    
    265.3Operating
      Income
    
    
    15.5
    
    
    12.9
    
    
    27.4
    
    
    17.8Other Income
    
    
    --
    
    
    0.4
    
    
    1.3
    
    
    0.7Net Interest
      Charges
    
    
    9.8
    
    
    10.2
    
    
    10.5
    
    
    9.4Net
      Income
    
    $
    5.7
    
    $
    3.1
    
    $
    18.2
    
    $
    9.1
 
 **Three
      Months Ended**
    
    **March
      31, 2003**
    
    **June
      30, 2003**
    
    **September
      30, 2003**
    
    **December
      31, 2003*****(In
      millions)***Operating
      Revenues
    
    $
    254.9
    
    $
    231.9
    
    $
    242.1
    
    $
    245.9Operating
      Expenses and Taxes
    
    
    242.2
    
    
    215.6
    
    
    228.5
    
    
    228.3Operating
      Income
    
    
    12.7
    
    
    16.3
    
    
    13.6
    
    
    17.6Other Income
      (Expense)
    
    
    (0.2
    )
    
    0.5
    
    
    0.5
    
    
    1.0Net Interest
      Charges
    
    
    8.3
    
    
    8.1
    
    
    9.0
    
    
    16.4Income Before
      Cumulative
      Effect of
      Accounting Change
    
    
    4.2
    
    
    8.7
    
    
    5.1
    
    
    2.2Cumulative
      Effect of Accounting
    
    
    1.1
    
    
    --
    
    
    --
    
    
    --Change (Net
      of Income Taxes)Net
      Income
    
    $
    5.3
    
    $
    8.7
    
    $
    5.1
    
    $
    2.2