**PENNSYLVANIA
POWER COMPANY**
 
 **2004
ANNUAL REPORT TO STOCKHOLDERS**
 
 
 
 Pennsylvania
Power Company, an electric utility operating company of FirstEnergy Corp. and a
wholly owned subsidiary of Ohio Edison Company, provides electric service to
approximately 157,000 customers in western Pennsylvania.
 
 
 
 
 
 
 **Contents**
    **Page**Glossary
      of Terms
    i-iiManagement
      Reports
    1Report
      of Independent Registered Public Accounting Firm
    2Selected
      Financial Data
    3Management's
      Discussion and Analysis
    4-13Consolidated
      Statements of Income
    14Consolidated
      Balance Sheets
    15Consolidated
      Statements of Capitalization
    16Consolidated
      Statements of Common Stockholder's Equity
    17Consolidated
      Statements of Preferred Stock
    17Consolidated
      Statements of Cash Flows
    18Consolidated
      Statements of Taxes
    19Notes
      to Consolidated Financial Statements
    20-35
 
 
   
  **GLOSSARY
OF TERMS**
 
 The
following abbreviations and acronyms are used in this report to identify
Pennsylvania Power Company and its affiliates:
 
 ATSI
    American
      Transmission Systems, Inc., owns and operates transmission
      facilitiesCEI
    The
      Cleveland Electric Illuminating Company, an affiliated Ohio electric
      utilityCompanies
    OE,
      CEI, TE, Penn, JCP&L, Met-Ed and PenelecFES
    FirstEnergy
      Solutions Corp., provides energy-related products and
    servicesFESC
    FirstEnergy
      Service Company, provides legal, financial, and other corporate support
      servicesFirstEnergy
    FirstEnergy
      Corp., a registered public utility holding companyJCP&L
    Jersey
      Central Power & Light Company, an affiliated New Jersey electric
      utilityMet-Ed
    Metropolitan
      Edison Company, an affiliated Pennsylvania electric
  utilityOE
    Ohio
      Edison Company, Penn's Ohio electric utility parent
  companyPenelec
    Pennsylvania
      Electric Company, an affiliated Pennsylvania electric utilityPenn
    Pennsylvania
      Power CompanyTE
    The
      Toledo Edison Company, an affiliated Ohio electric
  utility
 
 The
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 Nonmonetary
  Transactions"ARB
    Accounting
      Research BulletinARB
      43
    ARB
      No. 43, "Restatement and Revision of Accounting Research
      Bulletins"ARO
    Asset
      Retirement ObligationCO2
    Carbon
      DioxideCTC
    Competitive
      Transition ChargeECAR
    East
      Central Area Reliability Coordination AgreementEITF
    Emerging
      Issues Task ForceEITF
      03-1
    EITF
      Issue No. 03-1, "The Meaning of Other-Than-Temporary and Its Application
      to Certain
      Investments"EITF
      03-16
    EITF
      Issue No. 03-16, "Accounting for Investments in Limited Liability
      Companies"EITF
      97-4
    EITF
      Issue No. 97-4, "Deregulation of the Pricing of Electricity - Issues
      Related to the Application
      of
      FASB Statements No. 71 and 101"EPA
    Environmental
      Protection AgencyFASB
    Financial
      Accounting Standards BoardFERC
    Federal
      Energy Regulatory CommissionFMB
    First
      Mortgage BondsFSP
    FASB Staff
      PositionFSP EITF
      03-1-1
    FASB
      Staff Position No. EITF Issue 03-1-1, "Effective Date of Paragraphs 10-20
      of EITF Issue
      No.
      03-1,*The
      Meaning of Other-Than-Temporary Impairment and Its Application to Certain*
      *Investments"*FSP
      106-1
    FASB
      Staff Position No.106-1, "Accounting and Disclosure Requirements Related
      to the Medicare
      Prescription
      Drug, Improvement and Modernization Act of 2003"FSP
      106-2
    FASB
      Staff Position No.106-2, "Accounting and Disclosure Requirements Related
      to the Medicare
      Prescription
      Drug, Improvement and Modernization Act of 2003"FSP
      109-1
    FASB
      Staff Position No. 109-1, "Application of FASB Statement No. 109,
      Accounting for Income
      Taxes,
      to the Tax Deduction and Qualified Production Activities Provided by the
      American Jobs
      Creation
      Act of 2004"GAAP
    Accounting
      Principles Generally Accepted in the United StatesIRS
    Internal
      Revenue ServiceKWH
    Kilowatt-hoursLOC
    Letter
      of CreditMACT
    Maximum
      Achievable Control TechnologiesMedicare
      Act
    Medicare
      Prescription Drug, Improvement and Modernization Act of
    2003MISO
    Midwest
      Independent Transmission System Operator, Inc.Moody’s
    Moody’s
      Investors ServiceNAAQS
    National
      Ambient Air Quality StandardsNERC
    North
      American Electric Reliability CouncilNOV
    Notices
      of Violation
  i
 GLOSSARY OF TERMS,
Cont.
 NOx
    Nitrogen
      OxideNRC
    Nuclear
      Regulatory CommissionOCI
    Other
      Comprehensive IncomeOPEB
    Other
      Post-Employment BenefitsPJM
    PJM
      Interconnection L. L. C.PPUC
    Pennsylvania
      Public Utility CommissionPUCO
    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
      143
    SFAS
      No. 143, "Accounting for Asset Retirement Obligations"SFAS
      144
    SFAS
      No. 144, "Accounting for the Impairment or Disposal of Long-Lived
      Assets"SFAS
      150
    SFAS
      No. 150, "Accounting for Certain Financial Instruments with
      Characteristics of Both
      Liabilities
      and Equity"SO2
    Sulfur
      Dioxide
 
   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 Power Company:
 
 We have
completed an integrated audit of Pennsylvania Power 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 Power Company and its subsidiary 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.
 
 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
POWER COMPANY**
 
 **SELECTED
FINANCIAL DATA**
 
 
 **2004**
    
    **2003**
    
    **2002**
    
    **2001**
    
    **2000*****(Dollars
      in thousands)***Operating
      Revenues
    
    $
    549,121
    
    $
    526,581
    
    $
    506,407
    
    $
    498,401
    
    $
    383,112Operating
      Income
    
    $
    60,780
    
    $
    47,363
    
    $
    60,922
    
    $
    55,178
    
    $
    39,979Income
      Before Cumulative Effect
      of
      Accounting Change
    
    $
    59,076
    
    $
    37,833
    
    $
    47,717
    
    $
    41,041
    
    $
    22,847Net
      Income
    
    $
    59,076
    
    $
    48,451
    
    $
    47,717
    
    $
    41,041
    
    $
    22,847Earnings
      on Common Stock
    
    $
    56,516
    
    $
    45,263
    
    $
    44,018
    
    $
    37,338
    
    $
    19,143Total
      Assets
    
    $
    921,156
    
    $
    879,379
    
    $
    907,748
    
    $
    960,097
    
    $
    988,909**CAPITALIZATION
      AS OF DECEMBER 31:**Common
      Stockholder’s Equity
    
    $
    327,379
    
    $
    230,786
    
    $
    229,374
    
    $
    223,788
    
    $
    213,851Preferred
      Stock-Not
      Subject to Mandatory Redemption
    
    
    39,105
    
    
    39,105
    
    
    39,105
    
    
    39,105
    
    
    39,105Subject
      to Mandatory Redemption
    
    
    --
    
    
    --
    
    
    13,500
    
    
    14,250
    
    
    15,000Long-Term
      Debt and Other Long-Term Obligations
    
    
    133,887
    
    
    130,358
    
    
    185,499
    
    
    262,047
    
    
    270,368Total
      Capitalization
    
    $
    500,371
    
    $
    400,249
    
    $
    467,478
    
    $
    539,190
    
    $
    538,324**CAPITALIZATION
      RATIOS:**Common
      Stockholder’s Equity
    
    
    65.4
    %
    
    57.7
    %
    
    49.1
    %
    
    41.5
    %
    
    39.7
    %Preferred
      Stock-Not
      Subject to Mandatory Redemption
    
    
    7.8
    
    
    9.8
    
    
    8.3
    
    
    7.3
    
    
    7.3Subject
      to Mandatory Redemption
    
    
    --
    
    
    --
    
    
    2.9
    
    
    2.6
    
    
    2.8Long-Term
      Debt and Other Long-Term Obligations
    
    
    26.8
    
    
    32.5
    
    
    39.7
    
    
    48.6
    
    
    50.2Total
      Capitalization
    
    
    100.0
    %
    
    100.0
    %
    
    100.0
    %
    
    100.0
    %
    
    100.0
    %**DISTRIBUTION
      KILOWATT-HOUR DELIVERIES****(Millions):**Residential
    
    
    1,551
    
    
    1,506
    
    
    1,533
    
    
    1,391
    
    
    1,387Commercial
    
    
    1,299
    
    
    1,283
    
    
    1,268
    
    
    1,220
    
    
    1,198Industrial
    
    
    1,573
    
    
    1,464
    
    
    1,505
    
    
    1,540
    
    
    1,665Other
    
    
    7
    
    
    6
    
    
    6
    
    
    6
    
    
    6Total
    
    
    4,430
    
    
    4,259
    
    
    4,312
    
    
    4,157
    
    
    4,256**CUSTOMERS
      SERVED:**Residential
    
    
    138,377
    
    
    137,170
    
    
    136,410
    
    
    134,956
    
    
    121,066Commercial
    
    
    18,730
    
    
    18,455
    
    
    18,397
    
    
    18,153
    
    
    16,634Industrial
    
    
    219
    
    
    219
    
    
    220
    
    
    224
    
    
    177Other
    
    
    85
    
    
    85
    
    
    85
    
    
    87
    
    
    87Total
    
    
    157,411
    
    
    155,929
    
    
    155,112
    
    
    153,420
    
    
    137,964**NUMBER
      OF EMPLOYEES**
    
    
    200
    
    
    201
    
    
    201
    
    
    256
    
    
    275
 
  3
  **PENNSYLVANIA
POWER 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 and oversight, including by the Securities and
Exchange Commission as disclosed in our Securities and Exchange Commission
filings, the availability and cost of capital, the continuing availability and
operation of generating units, 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.*
 
 **Results
of Operations**
 
 Earnings
on common stock in 2004 increased to $57 million from $45 million in 2003.
Earnings in 2003 included an after-tax credit of $11 million from the cumulative
effect of an accounting change due to the adoption of SFAS 143 (see Note 8).
Income before the cumulative effect of an accounting change in 2003 was $38
million. Improved results in 2004 resulted from lower nuclear operating costs,
higher operating revenues and reduced net interest charges which were partially
offset by higher purchased power costs. Operating revenues were higher in 2004
primarily due to significant increases in wholesale sales to FES. Lower nuclear
operating costs in 2004 compared with 2003 were due to the absence of scheduled
nuclear refueling outages at Beaver Valley Unit 2 and Perry Plant in
2004.
 
 Earnings
on common stock in 2003 increased to $45 million from $44 million in 2002.
Income before the cumulative effect of an accounting change in 2003 decreased
21% to $38 million from $48 million in 2002. The lower earnings in 2003 were
primarily due to higher nuclear operating costs and purchased power costs. These
increased costs were partially offset by higher operating revenues, lower fuel
costs and reduced financing costs.
 
 Operating
revenues increased by $23 million or 4% in 2004 as compared with 2003. The
higher revenues primarily resulted from $14 million of increased wholesale
revenues in 2004 (primarily to FES) due to an increase in nuclear generation
available for sale and higher retail generation revenues. Sales increased in all
retail customer sectors for 2004 compared with 2003. Increased generation sales
and higher unit prices resulted in a $15 million increase in generation
revenues. Distribution deliveries increased in all customer classes in 2004
compared with 2003 reflecting an improving economy in our service area; lower
unit prices more than offset the effect of the higher deliveries in 2004,
resulting in a $6 million decrease in revenues. Higher deliveries to the steel
sector in 2004 were principally responsible for the increase in kilowatt-hour
sales to industrial customers.
 
 Operating
revenues increased by $20 million or 4% in 2003 as compared with 2002. The
higher revenues primarily resulted from increased wholesale revenues of $25
million in 2003, along with higher retail generation sales revenues of $3
million due to higher unit prices, partially offset by a 1% decrease in retail
kilowatt-hour sales. These electric generation revenue increases were partially
offset by $5 million of lower revenues from distribution deliveries. Wholesale
revenue increases from sales to FES reflected higher unit prices, which were
partially offset by lower kilowatt-hour sales due to reduced nuclear generation
available for sale to FES.
 Changes
in electric generation and distribution deliveries in 2004 and 2003 compared to
the prior years are summarized in the following table:
 4
 **Changes
      in KWH Sales**
    
    **2004**
    
    **2003*****Increase
      (Decrease)***Electric
      Generation:Retail
    
    
    4.1
    %
    
    (1.0
    )%Wholesale
    
    
    10.9
    %
    
    (11.6
    )%Total
      Electric Generation Sales
    
    
    8.0
    %
    
    (7.4
    )%Distribution
      Deliveries:Residential
    
    
    3.0
    %
    
    (1.8
    )%Commercial
    
    
    1.3
    %
    
    1.1
    %Industrial
    
    
    7.5
    %
    
    (2.7
    )%Total
      Distribution Deliveries
    
    
    4.0
    %
    
    (1.3
    )%
 
 
 *Operating
Expenses and Taxes*
 
 Total
operating expenses and taxes increased by $9 million in 2004 and $34 million in
2003 from the prior year. The following table presents changes from the prior
year by expense category.
 
 
 **Operating
      Expenses and Taxes - Changes**
    
    **2004**
    
    **2003*****Increase
      (Decrease)***
    
    ***(In
      millions)***Fuel
      costs
    
    $
    1
    
    $
    (4
    )Purchased
      power costs
    
    
    15
    
    
    9Nuclear
      operating costs
    
    
    (22
    )
    
    39Other
      operating costs
    
    
    (2
    )
    
    2Provision
      for depreciation
    
    
    1
    
    
    (2
    )Amortization
      of regulatory assets
    
    
    --
    
    
    (1
    )General
      taxes
    
    
    1
    
    
    (2
    )Income
      taxes
    
    
    15
    
    
    (7
    )Total
      operating expenses and taxes
    
    $
    9
    
    $
    34
 
 Higher
fuel costs in 2004 compared with 2003 resulted from increased nuclear generation
in 2004. Purchased power costs increased in 2004 compared with 2003 as a result
of a $15 million increase in power purchased from FES, reflecting higher unit
prices and higher kilowatt-hour purchases due to increased retail generation
requirements. Nuclear operating costs decreased $22 million, primarily due to
one scheduled refueling outage in 2004 compared to three scheduled refueling
outages in 2003.
 Lower
fuel costs in 2003, compared with 2002, resulted from reduced nuclear
generation. The increased purchased power costs in 2003 reflected higher unit
costs and increased kilowatt-hour purchases. Higher nuclear operating costs
occurred, in large part, due to three scheduled refueling outages in 2003,
compared with one scheduled refueling outage in 2002.
 
 Depreciation
charges were relatively unchanged in 2004 compared to the prior year while
depreciation decreased by $2 million in 2003 compared with 2002, primarily from
lower charges resulting from the implementation of SFAS 143, ($1 million for
2003) and revised service life assumptions for nuclear generating plants ($1
million for 2003).
 
 General
taxes decreased $2 million in 2003 from 2002 principally due to settled property
tax claims.
 
 *Net
Interest Charges*
 
 Net
interest charges continued to trend lower, decreasing by $7 million in 2004 and
by $3 million in 2003, compared with the prior years. We continued to redeem and
refinance outstanding debt, with 2004 redemptions totaling $64 million
(including mandatorily redeemable preferred stock). In 2003, redemptions totaled
$42 million (including mandatorily redeemable preferred stock).
 
 *Cumulative
Effect of Accounting Change*
 
 Upon
adoption of SFAS 143 in 2003, we recorded an after-tax credit to net income of
$11 million. The cumulative adjustment for unrecognized depreciation, accretion
offset by the reduction in the existing decommissioning liabilities and ceasing
the accounting practice of depreciating non-regulated generation assets using a
cost of removal component was an $18 million increase to income, or $11 million
net of income taxes.
  5
 **Capital
Resources and Liquidity**
 
 Our cash
requirements in 2004 for operating expenses, construction expenditures,
scheduled debt maturities and preferred stock redemptions were met without
increasing our net debt and preferred stock outstanding. We received $65 million
of equity contributions from OE in the second half of 2004. During 2005 and
thereafter, we expect to meet our contractual obligations with a combination of
cash from operations and funds from the capital markets.
 
 *Changes
in Cash Position*
 
 As of
December 31, 2004, we had $38,000 of cash and cash equivalents, compared
with $40,000 as of December 31, 2003. The major sources for changes in
these balances are summarized below.
 
 *Cash
Flows From Operating Activities*
 
 Net cash
provided from operating activities was $115 million in 2004, $116 million in
2003 and $105 million in 2002. Cash provided from 2004, 2003 and 2002 operating
activities are as follows:
 
 **Operating
      Cash Flows**
    
    **2004**
    
    **2003**
    
    **2002*****(In
      millions)***Cash
      earnings(1)
    
    $
    140
    
    $
    99
    
    $
    119Pension
      trust contribution(2)
    
    
    (8
    )
    
    --
    
    
    --Working
      capital and other
    
    
    (17
    )
    
    17
    
    
    (14
    )Total
    
    $
    115
    
    $
    116
    
    $
    105
 
 (1 )  Cash
earnings is a non-GAAP measure (see reconciliation below).
 (2)  Pension
trust contribution net of $5 million of income tax benefits.
 
 Cash
earnings (in the table above) is not a measure of performance calculated in
accordance with GAAP. We believe that cash earnings is a useful financial
measure because it provides investors and management with an additional means of
evaluating our cash-based operating performance. The following table reconciles
cash earnings with net income.
 
 **Reconciliation
      of Cash Earnings**
    
    **2004**
    
    **2003**
    
    **2002*****(In
      millions)***Net
      Income (GAAP)
    
    $
    59
    
    $
    48
    
    $
    48Non-Cash
      Charges (Credits):Provision
      for depreciation
    
    
    14
    
    
    13
    
    
    15Amortization
      of regulatory assets
    
    
    40
    
    
    41
    
    
    42Nuclear
      fuel and capital lease amortization
    
    
    17
    
    
    16
    
    
    19Deferred
      income taxes and investment
      taxcredits, net
    
    
    --
    
    
    (5
    )
    
    (8
    )Cumulative
      effect of accounting change
    
    
    --
    
    
    (18
    )
    
    --Other
      non-cash expenses
    
    
    10
    
    
    4
    
    
    3Cash
      earnings (Non-GAAP)
    
    $
    140
    
    $
    99
    
    $
    119
 
 Net cash
from operating activities decreased $1 million in 2004 compared with 2003 due to
a $34 million comparative change in working capital and an $8 million after-tax
voluntary pension trust contribution, partially offset by a $41 million increase
in cash earnings as described above under "Results of Operations". The working
capital decrease was due to changes of $14 million in receivables and $28
million in accrued tax balances partially offset by an $18 million increase in
accounts payable.
 
 Net cash
from operating activities increased $11 million in 2003 compared with 2002 due
to a $31 million increase in working capital, partially offset by a $20 million
decrease in cash earnings as described above under "Results of Operations".
Working capital increased principally as a result of changes of $25 million in
receivables and $21 million of accrued tax balances partially offset by an $18
million decrease in accounts payable.
 
 6
 *Cash
Flows From Financing Activities*
 
 Net cash
used for financing activities decreased to $25 million in 2004 from $76 million
in 2003. This decrease primarily reflects a $65 million equity contribution from
OE and a $19 million reduction of common stock dividends to OE. Net cash used
for financing activities in 2003 was unchanged from 2002 with a $14 million
increase in dividends to OE offsetting a $13 million reduction in net debt
redemptions.
 
 **Securities
      Issued or Redeemed**
    
    **2004**
    
    **2003**
    
    **2002*****(In
      millions)*****New
      Issues**Pollution
      Control Notes
    
    $
    --
    
    $
    --
    
    $
    15Short-Term
      Borrowings, Net
    
    
    1
    
    
    11
    
    
    --**Redemptions**First
      Mortgage Bonds
    
    $
    63
    
    $
    41
    
    $
    1Pollution
      Control Notes
    
    
    --
    
    
    --
    
    
    15Capital
      Fuel Leases
    
    
    --
    
    
    --
    
    
    41Preferred
      Stock
    
    
    1
    
    
    1
    
    
    1Other
    
    
    1
    
    
    --
    
    
    --$
    65
    
    $
    42
    
    $
    58
 
 In 2002,
net cash used for financing activities totaled $75 million, primarily due to
long-term debt redemptions and $32 million of dividend payments.
 
 We had
$469,000 of cash and temporary investments (which include short-term notes
receivable from associated companies) and $12 million of short-term indebtedness
with associated companies as of December 31, 2004. We have obtained
authorization from the SEC to incur short-term debt up to our charter limit of
$51 million (including the utility money pool). We have the capability to issue
$515 million of additional FMB on the basis of property additions and retired
bonds. Based upon applicable earnings coverage tests, we could issue up to $424
million of preferred stock (assuming no additional debt was issued) as of
December 31, 2004.
 
 We have
the ability to borrow from our regulated affiliates and FirstEnergy to meet our
short-term working capital requirements. FESC administers this money pool and
tracks surplus funds of FirstEnergy and its regulated subsidiaries, as well as
proceeds available from bank borrowings. Available bank borrowings include $1.75
billion from FirstEnergy’s and OE’s revolving credit facilities. Companies
receiving a loan under the money pool agreements must repay the principal amount
of such a loan, together with accrued interest, within 364 days of borrowing the
funds. The rate of interest is the same for each company receiving a loan from
the pool and is based on the average cost of funds available through the pool.
The average interest rate for borrowings under these arrangements in 2004 was
1.43%.
 
 In March
2004, we completed, through a separate wholly owned subsidiary, a receivables
financing arrangement that provides borrowing capability of up to $25 million.
The borrowing rate is based on bank commercial paper rates. We are required to
pay an annual facility fee of 0.40% on the entire finance limit. The facility
was undrawn as of December 31, 2004 and matures on March 29,
2005 . This
receivables financing arrangement is expected to be renewed prior to
expiration.
 
 On
December 1, 2004, Ohio Water Development Authority Series 1999-A pollution
control notes aggregating $5.2 million were remarketed in a Dutch Auction
interest mode and insured with municipal bond insurance.
 
 Our
access to capital markets and costs of financing are dependent on the ratings of
our securities and the securities of OE and FirstEnergy. The following table
shows securities ratings as of December 31, 2004. The ratings outlook on
all securities is stable.
 
 **Ratings
      of Securities****Securities**
    **S&P**
    **Moody’s**
    **Fitch****FirstEnergy**
    Senior
      unsecured
    BB+
    Baa3
    BBB-**OE**
    Senior
      secured
    BBB
    Baa1
    BBB+Senior
      unsecured
    BB+
    Baa2
    BBBPreferred
      stock
    BB
    Ba1
    BBB-**Penn**
    Senior
      secured
    BBB
    Baa1
    BBB+Senior
      unsecured(1)
    BB+
    Baa2
    BBBPreferred
      stock
    BB
    Ba1
    BBB-








(1)
    Penn’s
      only senior unsecured debt obligations are pollution control revenue
      refunding bonds issued in the name of the Ohio
      Air
      QualityDevelopment
      Authority to which this rating applies.










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*





Net cash
used in investing activities totaled $90 million in 2004 compared to $41 million
in 2003. The $49 million increase in 2004 reflects $22 million of increased
property additions and a reduction of $28 million in loan repayments from
associated companies. Expenditures for property additions include expenditures
supporting our distribution of electricity.





Net cash
used in investing activities increased to $41 million in 2003 from $28 million
in 2002. The $13 million increase in 2003 reflects $25 million of increased
property additions, partially offset by a $15 million increase in loan
repayments from associated companies.





Our
capital spending for the period 2005-2007 is expected to be about $227 million
(excluding nuclear fuel) of which approximately $82 million applies to 2005.
Investments for additional nuclear fuel during the 2005-2007 period are
estimated to be approximately $63 million, of which about $13 million relates to
2005. During the same periods, our nuclear fuel investments are expected to be
reduced by approximately $52 million and $17 million, respectively, as the
nuclear fuel is consumed. We had no other material obligations as of
December 31, 2004 that have not been recognized on our Consolidated Balance
Sheet.





**Contractual
Obligations**





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





**Contractual
      Obligations**
    
    **Total**
    
    **2005**
    
    **2006-2007**
    
    **2008-2009**
    
    **Thereafter*****(In
      millions)***Long-term
      debt (3)
    
    $
    148
    
    $
    1
    
    $
    2
    
    $
    2
    
    $
    143Preferred
      stock (1)
    
    
    13
    
    
    1
    
    
    12
    
    
    --
    
    
    --Short-term
      borrowings
    
    
    12
    
    
    12
    
    
    --
    
    
    --
    
    
    --Operating
      leases
    
    
    1
    
    
    --
    
    
    --
    
    
    --
    
    
    1Purchases
      (2)
    
    
    81
    
    
    13
    
    
    49
    
    
    19
    
    
    --Total
    
    $
    255
    
    $
    27
    
    $
    63
    
    $
    21
    
    $
    144





(1)  Subject
to mandatory redemption.


(2)  Fuel and
power purchases under contracts with fixed or minimum quantities and approximate
timing.


(3) 
Amounts reflected do not include interest on long-term debt.


**Interest
Rate Risk**





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





The
table below presents principal amounts and related weighted average interest
rates by year of maturity for our investment portfolio, debt obligations and
preferred stock with mandatory redemption provisions.





8








**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
    
    
    
    
    
    
    
    $
    1
    
    $
    1
    
    $
    1
    
    $
    116
    
    **$**
    **119**
    
    **$**
    **125**Average
      interest rate
    
    
    
    
    
    
    
    
    7.8
    %
    
    7.8
    %
    
    7.8
    %
    
    5.5
    %
    
    5.5
    %LiabilitiesLong-term
      Debt and Other
      Long-Term
      Obligations:Fixed
      rate
    
    $
    1
    
    $
    1
    
    $
    1
    
    $
    1
    
    $
    1
    
    $
    81
    
    **$**
    **86**
    
    **$**
    **98**Average
      interest rate
    
    
    9.7
    %
    
    9.7
    %
    
    9.7
    %
    
    9.7
    %
    
    9.7
    %
    
    6.4
    %
    
    6.6
    %Variable
      rate
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    62
    
    **$**
    **62**
    
    **$**
    **62**Average
      interest rate
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2.1
    %
    
    2.1
    %Preferred
      Stock Subject to
      Mandatory
      Redemption
    
    $
    1
    
    $
    1
    
    $
    11
    
    
    
    
    
    
    
    
    
    
    **$**
    **13**
    
    **$**
    **12**Average
      dividend rate
    
    
    7.6
    %
    
    7.6
    %
    
    7.6
    %
    
    
    
    
    
    
    
    
    
    
    7.6
    %Short-term
      Borrowings
    
    $
    12
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    **$**
    **12**
    
    **$**
    **12**Average
      interest rate
    
    
    2.0
    %
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2.0
    %





**Equity
Price Risk**





Included
in our nuclear decommissioning trust investments are marketable equity
securities carried at their market value of approximately $57 million and $50
million as of 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**





We have
a continuing responsibility to provide power to those customers not choosing to
receive power from an alternative energy supplier subject to certain limits.
Adopting new approaches to regulation and experiencing new forms of competition
have created new uncertainties. We continue to deliver power to homes and
businesses through our existing distribution system, which remains
regulated.





*Regulatory
Matters*





Pennsylvania
enacted its electric utility competition law in 1996 with the phase in of
customer choice for electric generation suppliers completed as of
January 1, 2001. We continue to deliver power to homes and businesses
through our distribution system, which remains regulated by the PPUC. Our rates
have been restructured to itemize (unbundle) the current price of electricity
into its component elements - including generation, transmission, distribution
and stranded cost recovery. In the event customers obtain power from an
alternative source, the generation portion of our rates is excluded from their
bill and the customers receive a generation charge from the alternative
supplier. The stranded cost recovery portion of rates provides for recovery of
certain amounts not otherwise considered recoverable in a competitive generation
market, including regulatory assets. Under the rate restructuring plan, we are
entitled to recover $236 million of stranded costs through the CTC that began in
1999 and ends in 2006.





On
January 16, 2004, the PPUC initiated a formal investigation of whether our
"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, we filed a
settlement agreement with the PPUC that addresses the issues related to this
investigation. As part of the settlement, we, Met-Ed and Penelec agreed to
enhance service reliability, ongoing periodic performance reporting and
communications with customers and to collectively maintain our 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.





See Note
6 to the consolidated financial statements for a complete and detailed
discussion of regulatory matters.








9





*Environmental
Matters*





We
believe we are in compliance with current SO2and
NOxreduction requirements under the Clean Air Act Amendments of 1990. In 1998, the
EPA finalized regulations requiring additional NOxreductions in the future from our Ohio and Pennsylvania facilities. Various
regulatory and judicial actions have since sought to further define
NOxreduction requirements (see Note 10(B) - Environmental Matters). We continue to
evaluate our compliance plans and other compliance options.





*Clean
Air Act Compliance-*





We are
required to meet federally approved SO2 regulations. Violations of
such regulations can result in shutdown of the generating unit involved and/or
civil or criminal penalties of up to $32,500 for each day the unit is in
violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio
that allows for compliance based on a 30-day averaging period. We cannot predict
what action the EPA may take in the future with respect to the interim
enforcement policy.





We
believe we are complying with SO2 reduction requirements under the
Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more
electricity from lower-emitting plants, and/or using emission allowances. NOx
reductions required by the 1990 Amendments are being achieved through combustion
controls and the generation of more electricity at lower-emitting plants. In
September 1998, the EPA finalized regulations requiring additional
NOx reductions from our facilities. The EPA's NOx
Transport Rule imposes uniform reductions of NOx emissions (an
approximate 85% reduction in utility plant NOx emissions from
projected 2007 emissions) across a region of nineteen states (including Ohio and
Pennsylvania) and the District of Columbia based on a conclusion that such
NOx emissions are contributing significantly to ozone levels in the
eastern United States. We believe our facilities are also complying with
NOx budgets established under State Implementation Plans (SIP)
through combustion controls and post-combustion controls, including Selective
Catalytic Reduction and Selective Non-Catalytic Reduction systems, and/or using
emission allowances.





*National
Ambient Air Quality Standards-*





In July
1997, the EPA promulgated changes in the NAAQS for ozone and proposed a new
NAAQS for fine particulate matter. On December 17, 2003, the EPA proposed
the "Interstate Air Quality Rule" covering a total of 29 states (including Ohio
and Pennsylvania) and the District of Columbia based on proposed findings that
air pollution emissions from 29 eastern states and the District of Columbia
significantly contribute to nonattainment of the NAAQS for fine particles and/or
the "8-hour" ozone NAAQS in other states. The EPA has proposed the Interstate
Air Quality Rule to "cap-and-trade" NOx and SO2 emissions
in two phases (Phase I in 2010 and Phase II in 2015). According to the EPA,
SO2 emissions would be reduced by approximately 3.6 million tons
annually by 2010, across states covered by the rule, with reductions ultimately
reaching more than 5.5 million tons annually. NOx emission reductions
would measure about 1.5 million tons in 2010 and 1.8 million tons in 2015. The
future cost of compliance with these proposed regulations may be substantial and
will depend on whether and how they are ultimately implemented by the states in
which we operate affected facilities.





*Mercury
Emissions-*





In
December 2000, the EPA announced it would proceed with the development of
regulations regarding hazardous air pollutants from electric power plants,
identifying mercury as the hazardous air pollutant of greatest concern. On
December 15, 2003, the EPA proposed two different approaches to reduce
mercury emissions from coal-fired power plants. The first approach would require
plants to install controls known as MACT based on the type of coal burned.
According to the EPA, if implemented, the MACT proposal would reduce nationwide
mercury emissions from coal-fired power plants by 14 tons to approximately 34
tons per year. The second approach proposes a cap-and-trade program that would
reduce mercury emissions in two distinct phases. Initially, mercury emissions
would be reduced by 2010 as a "co-benefit" from implementation of SO2
and NOx emission caps under the EPA's proposed Interstate Air Quality
Rule. Phase II of the mercury cap-and-trade program would be implemented in 2018
to cap nationwide mercury emissions from coal-fired power plants at 15 tons per
year. The EPA has agreed to choose between these two options and issue a final
rule by March 15, 2005. The future cost of compliance with these
regulations may be substantial.





10








*W.
H. Sammis Plant-*





In 1999
and 2000, the EPA issued NOV or Compliance Orders to nine utilities covering 44
power plants, including the W. H. Sammis Plant, which is owned by OE and Penn.
In addition, the U.S. Department of Justice filed eight civil complaints against
various investor-owned utilities, which included a complaint against OE and Penn
in the U.S. District Court for the Southern District of Ohio. These cases are
referred to as New Source Review cases. The NOV and complaint allege violations
of the Clean Air Act based on operation and maintenance of the W. H. Sammis
Plant dating back to 1984. The complaint requests permanent injunctive relief to
require the installation of "best available control technology" and civil
penalties of up to $27,500 per day of violation. On August 7, 2003, the
United States District Court for the Southern District of Ohio ruled that 11
projects undertaken at the W. H. Sammis Plant between 1984 and 1998 required
pre-construction permits under the Clean Air Act. The ruling concludes the
liability phase of the case, which deals with applicability of Prevention of
Significant Deterioration provisions of the Clean Air Act. The remedy phase of
the trial to address any civil penalties and what, if any, actions should be
taken to further reduce emissions at the plant has been delayed without
rescheduling by the Court because the parties are engaged in meaningful
settlement negotiations. The Court indicated, in its August 2003 ruling, that
the remedies it "may consider and impose involved a much broader, equitable
analysis, requiring the Court to consider air quality, public health, economic
impact, and employment consequences. The Court may also consider the less than
consistent efforts of the EPA to apply and further enforce the Clean Air Act."
The potential penalties that may be imposed, as well as the capital expenditures
necessary to comply with substantive remedial measures that may be required,
could have a material adverse impact on FirstEnergy's, OE's and our respective
financial condition and results of operations. While the parties are engaged in
meaningful settlement discussions, management is unable to predict the ultimate
outcome of this matter and no liability has been accrued as of December 31,
2004.





*Regulation
of Hazardous Waste-*





As a result of the Resource
Conservation and Recovery Act of 1976, as amended, and the Toxic Substances
Control Act of 1976, federal and state hazardous waste regulations have been
promulgated. Certain fossil-fuel combustion waste products, such as coal ash,
were exempted from hazardous waste disposal requirements pending the EPA's
evaluation of the need for future regulation. The EPA subsequently determined
that regulation of coal ash, as a hazardous waste is unnecessary. In April 2000,
the EPA announced that it will develop national standards regulating disposal of
coal ash under its authority to regulate nonhazardous waste.





*Climate
Change-*





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





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




*Clean Water
Act-*





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


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





11





Legal
Matters





There
are various lawsuits, claims (including claims for asbestos exposure) and
proceedings related to our normal business operations pending against us. The
most significant are described below.





On
August 12, 2004, the NRC notified FENOC that it will increase its regulatory
oversight of the Perry Nuclear Power Plant as a result of problems with safety
system equipment over the past two years. FENOC operates the Perry Nuclear Power
Plant, in which we own a 5.24% interest. Although the NRC noted that the
plant continues to operate safely, the agency has indicated that its increased
oversight will include an extensive NRC team inspection to assess the equipment
problems and the sufficiency of FENOC's corrective actions. The outcome of these
matters could include NRC enforcement action or other impacts on operating
authority. As a result, these matters could have a material adverse effect on
FirstEnergy's or its subsidiaries' financial condition.





**Critical
Accounting Policies**





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





*Regulatory
Accounting*





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





*Revenue
Recognition*





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





*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.





12





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 $13 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
$8 million. As prescribed by SFAS 87, we increased our additional minimum
liability by $4 million, recording an increase in an intangible asset of $1
million and charging $3 million to OCI. The balance in AOCL of $14 million (net
of $10 million in deferred taxes) will reverse in future periods to the extent
the fair value of trust assets exceeds the accumulated benefit obligation.





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





*Long-Lived
Assets*





In
accordance with SFAS 144, we periodically evaluate our long-lived assets to
determine whether conditions exist that would indicate that the carrying value
of an asset might not be fully recoverable. The accounting standard requires
that if the sum of future cash flows (undiscounted) expected to result from an
asset is less than the carrying value of the asset, an asset impairment must be
recognized in the financial statements. If impairment has occurred, we recognize
a loss - calculated as the difference between the carrying value and the
estimated fair value of the asset (discounted future net cash flows).





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





*Nuclear
Decommissioning*





In
accordance with SFAS 143, we recognize an ARO for the future decommissioning of
our nuclear power plants. The ARO liability represents an estimate of the fair
value of our current obligation related to nuclear decommissioning and the
retirement of other assets. A fair value measurement inherently involves
uncertainty in the amount and timing of settlement of the liability. We used an
expected cash flow approach to measure the fair value of the nuclear
decommissioning ARO. This approach applies probability weighting to discounted
future cash flow scenarios that reflect a range of possible outcomes. The
scenarios consider settlement of the ARO at the expiration of the nuclear power
plants' current license and settlement based on an extended license
term.





**NEW
ACCOUNTING STANDARDS AND INTERPRETATIONS**





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





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










13








**PENNSYLVANIA
POWER COMPANY**





**CONSOLIDATED
STATEMENTS OF INCOME**








**For
      the Years Ended December 31,**
    **2004**
    
    **2003**
    
    **2002*****(In
      thousands)*****OPERATING
      REVENUES (Note 2(I))**
    $
    549,121
    
    $
    526,581
    
    $
    506,407**OPERATING
      EXPENSES AND TAXES:**Fuel
    
    22,894
    
    
    21,443
    
    
    25,180Purchased
      power (Note 2(I))
    
    181,031
    
    
    165,643
    
    
    156,788Nuclear
      operating costs
    
    106,659
    
    
    128,895
    
    
    90,024Other
      operating costs (Note 2(I))
    
    51,180
    
    
    52,809
    
    
    50,523Provision
      for depreciation
    
    14,134
    
    
    13,017
    
    
    15,197Amortization
      of regulatory assets
    
    40,012
    
    
    40,789
    
    
    41,566General
      taxes
    
    23,607
    
    
    22,458
    
    
    24,474Income
      taxes
    
    48,824
    
    
    34,164
    
    
    41,733Total
      operating expenses and taxes
    
    488,341
    
    
    479,218
    
    
    445,485**OPERATING
      INCOME**
    
    60,780
    
    
    47,363
    
    
    60,922**OTHER
      INCOME (NET OF INCOME TAXES) (Note 2(I))**
    
    3,464
    
    
    2,807
    
    
    1,960**NET
      INTEREST CHARGES:**Interest
      on long-term debt
    
    8,250
    
    
    14,228
    
    
    15,521Allowance
      for borrowed funds used during construction
    
    (4,563
    )
    
    (3,189
    )
    
    (1,509
    )Other
      interest expense
    
    1,481
    
    
    1,298
    
    
    1,153Net
      interest charges
    
    5,168
    
    
    12,337
    
    
    15,165**INCOME
      BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE**
    
    59,076
    
    
    37,833
    
    
    47,717Cumulative
      effect of accounting change (net of income taxes of
      $7,532,000)(Note
      2(G))
    
    --
    
    
    10,618
    
    
    --**NET
      INCOME**
    
    59,076
    
    
    48,451
    
    
    47,717**PREFERRED
      STOCK DIVIDEND REQUIREMENTS**
    
    2,560
    
    
    3,188
    
    
    3,699**EARNINGS
      ON COMMON STOCK**
    $
    56,516
    
    $
    45,263
    
    $
    44,018














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








14





**PENNSYLVANIA
POWER COMPANY**





**CONSOLIDATED
BALANCE SHEETS**





**As
      of December 31,**
    **2004**
    
    **2003*****(In
      thousands****)***ASSETS****UTILITY
      PLANT:**In
      service
    $
    866,303
    
    $
    808,637Less-Accumulated
      provision for depreciation
    
    356,020
    
    
    324,710510,283
    
    
    483,927Construction
      work in progress-Electric
      plant
    
    104,366
    
    
    68,091Nuclear
      fuel
    
    3,362
    
    
    360107,728
    
    
    68,451618,011
    
    
    552,378**OTHER
      PROPERTY AND INVESTMENTS:**Nuclear
      plant decommissioning trusts (Note 4)
    
    143,062
    
    
    133,867Long-term
      notes receivable from associated companies
    
    32,985
    
    
    39,179Other
    
    722
    
    
    2,195176,769
    
    
    175,241**CURRENT
      ASSETS:**Cash
      and cash equivalents
    
    38
    
    
    40Notes
      receivable from associated companies
    
    431
    
    
    399Receivables-Customers
      (less accumulated provisions of $888,000 and $769,000,respectively,
      for uncollectible accounts)
    
    44,282
    
    
    44,861Associated
      companies
    
    23,016
    
    
    24,965Other
    
    1,656
    
    
    1,047Materials
      and supplies, at average cost
    
    37,923
    
    
    33,918Prepayments
      and other
    
    8,924
    
    
    9,383116,270
    
    
    114,613**DEFERRED
      CHARGES:**Regulatory
      assets
    
    --
    
    
    27,513Other
    
    10,106
    
    
    9,63410,106
    
    
    37,147$
    921,156
    
    $
    879,379**CAPITALIZATION
      AND LIABILITIES****CAPITALIZATION**(See
      Consolidated Statements of Capitalization):Common
      stockholder’s equity
    $
    327,379
    
    $
    230,786Preferred
      stock not subject to mandatory redemption
    
    39,105
    
    
    39,105Long-term
      debt and other long-term obligations
    
    133,887
    
    
    130,358500,371
    
    
    400,249**CURRENT
      LIABILITIES:**Currently
      payable long-term debt
    
    26,524
    
    
    93,474Accounts
      payable-Associated
      companies
    
    46,368
    
    
    40,172Other
    
    1,436
    
    
    1,294Notes
      payable to associated companies
    
    11,852
    
    
    11,334Accrued
      taxes
    
    14,055
    
    
    27,091Accrued
      interest
    
    1,872
    
    
    4,396Other
    
    8,802
    
    
    8,444110,909
    
    
    186,205**NONCURRENT
      LIABILITIES:**Accumulated
      deferred income taxes
    
    93,418
    
    
    97,871Accumulated
      deferred investment tax credits
    
    3,222
    
    
    3,516Asset
      retirement obligation
    
    138,284
    
    
    129,546Retirement
      benefits
    
    49,834
    
    
    54,057Regulatory
      liabilities
    
    18,454
    
    
    --Other
    
    6,664
    
    
    7,935309,876
    
    
    292,925**COMMITMENTS
      AND CONTINGENCIES**(Notes
      5 and 10)$
    921,156
    
    $
    879,379








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





15





**PENNSYLVANIA
POWER COMPANY**





**CONSOLIDATED
STATEMENTS OF CAPITALIZATION**


**As of
      December 31,**
    **2004**
    
    **2003*****(Dollars
      in thousands, except per share amounts)*****COMMON
      STOCKHOLDER’S EQUITY:**Common stock,
      $30 par value, 6,500,000 shares authorized, 6,290,000 shares
      outstanding
    $
    188,700
    
    $
    188,700Other paid-in
      capital
    
    64,690
    
    
    (310)
    )Accumulated
      other comprehensive loss (Note 2(F))
    
    (13,706
    )
    
    (11,783
    )Retained
      earnings (Note 7(A))
    
    87,695
    
    
    54,179Total common
      stockholder’s equity
    
    327,379
    
    
    230,786


**Number
      of Shares**
    
    **Optional****Outstanding**
    
    **Redemption
      Price****2004**
    
    **2003**
    
    **Per
      Share**
    
    **Aggregate****PREFERRED
      STOCK (Note 7(B)):**Cumulative,
      $100 par value-Authorized
      1,200,000 shares4.24%
    
    40,000
    
    
    40,000
    
    $
    103.13
    
    $
    4,125
    
    
    4,000
    
    
    4,0004.25%
    
    41,049
    
    
    41,049
    
    
    105.00
    
    
    4,310
    
    
    4,105
    
    
    4,1054.64%
    
    60,000
    
    
    60,000
    
    
    102.98
    
    
    6,179
    
    
    6,000
    
    
    6,0007.75%
    
    250,000
    
    
    250,000
    
    
    100.00
    
    
    25,000
    
    
    25,000
    
    
    25,000Total
    
    391,049
    
    
    391,049
    
    
    
    
    $
    39,614
    
    
    39,105
    
    
    39,105**LONG-TERM
      DEBT AND OTHER****LONG-TERM
      OBLIGATIONS (Note 7(C)):**First
      mortgage bonds-9.740%
      due 2005-2019
    
    
    
    
    
    
    
    
    
    
    
    
    
    14,643
    
    
    15,6176.375%
      due 2004
    
    
    
    
    
    
    
    
    
    
    
    
    
    --
    
    
    20,5006.625%
      due 2004
    
    
    
    
    
    
    
    
    
    
    
    
    
    --
    
    
    14,0008.500%
      due 2022
    
    
    
    
    
    
    
    
    
    
    
    
    
    --
    
    
    27,2507.625%
      due 2023
    
    
    
    
    
    
    
    
    
    
    
    
    
    6,500
    
    
    6,500Total
      first mortgage bonds
    
    
    
    
    
    
    
    
    
    
    
    
    
    21,143
    
    
    83,867Secured
      notes-5.400% due 2013
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,000
    
    
    1,0005.400%
      due 2017
    
    
    
    
    
    
    
    
    
    
    
    
    
    10,600
    
    
    10,600*  1.700%
      due 2017
    
    
    
    
    
    
    
    
    
    
    
    
    
    17,925
    
    
    17,9255.900%
      due 2018
    
    
    
    
    
    
    
    
    
    
    
    
    
    16,800
    
    
    16,800*  1.700%
      due 2021
    
    
    
    
    
    
    
    
    
    
    
    
    
    14,482
    
    
    14,4826.150% due 2023
    
    
    
    
    
    
    
    
    
    
    
    
    
    12,700
    
    
    12,700* 2.000%
      due 2027
    
    
    
    
    
    
    
    
    
    
    
    
    
    10,300
    
    
    10,3005.375%
      due 2028
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,734
    
    
    1,7345.450%
      due 2028
    
    
    
    
    
    
    
    
    
    
    
    
    
    6,950
    
    
    6,9506.000%
      due 2028
    
    
    
    
    
    
    
    
    
    
    
    
    
    14,250
    
    
    14,2505.950%
      due 2029
    
    
    
    
    
    
    
    
    
    
    
    
    
    238
    
    
    238*  
      1.800%
      due 2033
    
    
    
    
    
    
    
    
    
    
    
    
    
    5,200
    
    
    --Total
      secured notes
    
    
    
    
    
    
    
    
    
    
    
    
    
    112,179
    
    
    106,979Unsecured
      notes-*3.375%
      due 2029
    
    
    
    
    
    
    
    
    
    
    
    
    
    14,500
    
    
    14,500*5.900%
      due 2033
    
    
    
    
    
    
    
    
    
    
    
    
    
    --
    
    
    5,200Total
      unsecured notes
    
    
    
    
    
    
    
    
    
    
    
    
    
    14,500
    
    
    19,700Preferred
      stock subject to mandatory redemption
    
    
    
    
    
    
    
    
    
    
    
    12,750
    
    
    13,500Net
      unamortized discount on debt
    
    
    
    
    
    
    
    
    
    
    
    
    
    (161
    )
    
    (214
    )Long-term
      debt due within one year
    
    
    
    
    
    
    
    
    
    
    
    
    
    (26,524
    )
    
    (93,474
    )Total
      long-term debt and other long-
      term
      obligations
    
    
    
    
    
    
    
    
    
    
    
    
    
    133,887
    
    
    130,358**TOTAL
      CAPITALIZATION**
    
    
    
    
    
    
    
    
    
    
    
    
    $
    500,371
    
    $
    400,249








*
Denotes variable rate issue with December 31, 2004 interest rate
shown.








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





16





**PENNSYLVANIA
POWER COMPANY**





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








**Accumulated****Other**
    
    **Other****Comprehensive**
    
    **Number**
    
    **Par**
    
    **Paid-In**
    
    **Comprehensive**
    
    **Retained****Income**
    
    **of
      Shares**
    
    **Value**
    
    **Capital**
    
    **Income
      (Loss)**
    
    **Earnings*****(Dollars
      in thousands)***Balance,
      January 1, 2002
    
    
    
    
    6,290,000
    
    $
    188,700
    
    $
    (310
    )
    $
    --
    
    $
    35,398Net
      income
    $
    47,717
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    47,717Minimum
      liability for unfunded retirementbenefits,
      net of $(7,045,000) ofincome
      taxes
    
    (9,932
    )
    
    
    
    
    
    
    
    
    
    
    (9,932
    )Comprehensive
      income
    $
    37,785Cash
      dividends on preferred stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (3,699
    )Cash
      dividends on common stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (28,500
    )Balance,
      December 31, 2002
    
    
    
    
    6,290,000
    
    
    188,700
    
    
    (310
    )
    
    (9,932
    )
    
    50,916Net
      income
    $
    48,451
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    48,451Minimum
      liability for unfunded retirementbenefits,
      net of $(1,290,000) ofincome
      taxes
    
    (1,851
    )
    
    
    
    
    
    
    
    
    
    
    (1,851
    )Comprehensive
      income
    $
    46,600Cash
      dividends on preferred stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (3,188
    )Cash
      dividends on common stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (42,000
    )Balance,
      December 31, 2003
    
    
    
    
    6,290,000
    
    
    188,700
    
    
    (310
    )
    
    (11,783
    )
    
    54,179Net
      income
    $
    59,076
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    59,076Minimum
      liability for unfunded retirementbenefits,
      net of $(1,372,000) ofincome
      taxes
    
    (1,923
    )
    
    
    
    
    
    
    
    
    
    
    (1,923
    )Comprehensive
      income
    $
    57,153Cash
      dividends on preferred stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (2,560
    )Cash
      dividends on common stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (23,000
    )Equity
      contribution from parent
    
    
    
    
    
    
    
    
    
    
    65,000Balance,
      December 31, 2004
    
    
    
    
    6,290,000
    
    $
    188,700
    
    $
    64,690
    
    $
    (13,706
    )
    $
    87,695








**CONSOLIDATED
STATEMENTS OF PREFERRED STOCK**





**Not
      Subject to**
    
    **Subject
      to****Mandatory
      Redemption**
    
    **Mandatory
      Redemption****Number**
    
    **Par**
    
    **Number**
    
    **Par****of
      Shares**
    
    **Value**
    
    **of
      Shares**
    
    **Value*****(Dollars
      in thousands)***Balance,
      January 1, 2002
    
    391,049
    
    $
    39,105
    
    
    150,000
    
    $
    15,000Redemptions-7.625%
      Series
    
    
    
    
    
    
    
    (7,500
    )
    
    (750
    )Balance,
      December 31, 2002
    
    391,049
    
    
    39,105
    
    
    142,500
    
    
    14,250Redemptions-7.625%
      Series
    
    
    
    
    
    
    
    (7,500
    )
    
    (750
    )Balance,
      December 31, 2003
    
    391,049
    
    
    39,105
    
    
    135,000
    
    
    13,500
    *Redemptions-7.625%
      Series
    
    
    
    
    
    
    
    (7,500
    )
    
    (750
    )Balance,
      December 31, 2004
    
    391,049
    
    $
    39,105
    
    
    127,500
    
    $
    12,750
    *








*  Preferred
stock subject to mandatory redemption is classified as debt under SFAS
150.





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








17





**PENNSYLVANIA
POWER COMPANY**





**CONSOLIDATED
STATEMENTS OF CASH FLOWS**





**For
      the Years Ended December 31,**
    **2004**
    
    **2003**
    
    **2002*****(In
      thousands)*****CASH
      FLOWS FROM OPERATING ACTIVITIES:**Net
      income
    $
    59,076
    
    $
    48,451
    
    $
    47,717Adjustments
      to reconcile net income to net cash from operating
    activities:Provision
      for depreciation
    
    14,134
    
    
    13,017
    
    
    15,197Amortization
      of regulatory assets
    
    40,012
    
    
    40,789
    
    
    41,566Nuclear
      fuel and lease amortization
    
    16,790
    
    
    15,947
    
    
    19,204Deferred
      income taxes and investment tax credits, net
    
    5,011
    
    
    (5,228
    )
    
    (7,932
    )Cumulative
      effect of accounting change (Note 2(G))
    
    --
    
    
    (18,150
    )
    
    --Pension
      trust contribution
    
    (12,934
    )
    
    --
    
    
    --Decrease
      (Increase) in operating assets:Receivables
    
    1,919
    
    
    16,276
    
    
    (8,434
    )Materials
      and supplies
    
    (4,005
    )
    
    (3,609
    )
    
    (4,711
    )Prepayments
      and other current assets
    
    459
    
    
    (4,037
    )
    
    336Increase
      (Decrease) in operating liabilities:Accounts
      payable
    
    6,338
    
    
    (11,163
    )
    
    6,338Accrued
      taxes
    
    (13,036
    )
    
    14,584
    
    
    (6,346
    )Accrued
      interest
    
    (2,524
    )
    
    (1,162
    )
    
    294Asset
      retirement obligation, net
    
    (1,242
    )
    
    4,112
    
    
    --Other
    
    5,097
    
    
    5,814
    
    
    1,361Net
      cash provided from operating activities
    
    115,095
    
    
    115,641
    
    
    104,590**CASH
      FLOWS FROM FINANCING ACTIVITIES:**New
      Financing-Long-term
      debt
    
    --
    
    
    --
    
    
    14,500Short-term
      borrowings, net
    
    518
    
    
    11,334
    
    
    --Equity
      contribution from parent
    
    65,000
    
    
    --
    
    
    --Redemptions
      and Repayments-Preferred
      stock
    
    (750
    )
    
    (750
    )
    
    (750
    )Long-term
      debt
    
    (63,903
    )
    
    (41,155
    )
    
    (56,837
    )Dividend
      Payments-Common
      stock
    
    (23,000
    )
    
    (42,000
    )
    
    (28,500
    )Preferred
      stock
    
    (2,560
    )
    
    (3,188
    )
    
    (3,699
    )Net
      cash used for financing activities
    
    (24,695
    )
    
    (75,759
    )
    
    (75,286
    )**CASH
      FLOWS FROM INVESTING ACTIVITIES:**Property
      additions
    
    (93,320
    )
    
    (70,864
    )
    
    (46,060
    )Contributions
      to nuclear decommissioning trusts
    
    (1,594
    )
    
    (1,594
    )
    
    (1,594
    )Loan
      repayments from associated companies
    
    6,162
    
    
    34,660
    
    
    19,463Other
    
    (1,650
    )
    
    (3,266
    )
    
    42Net
      cash used for investing activities
    
    (90,402
    )
    
    (41,064
    )
    
    (28,149
    )Net
      increase (decrease) in cash and cash equivalents
    
    (2
    )
    
    (1,182
    )
    
    1,155Cash
      and cash equivalents at beginning of year
    
    40
    
    
    1,222
    
    
    67Cash
      and cash equivalents at end of year
    $
    38
    
    $
    40
    
    $
    1,222**SUPPLEMENTAL
      CASH FLOWS INFORMATION:**Cash
      paid during the year-Interest
      (net of amounts capitalized)
    $
    6,885
    
    $
    12,449
    
    $
    13,771Income
      taxes
    $
    68,869
    
    $
    33,502
    
    $
    60,078











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










18





**PENNSYLVANIA
POWER COMPANY**





**CONSOLIDATED
STATEMENTS OF TAXES**





**For
      the Years Ended December 31,**
    **2004**
    
    **2003**
    
    **2002*****(In
      thousands)*****GENERAL
      TAXES:**State
      gross receipts*
    $
    19,234
    
    $
    18,028
    
    $
    18,516Real
      and personal property
    
    1,288
    
    
    2,262
    
    
    3,729State
      capital stock
    
    2,014
    
    
    952
    
    
    1,357Social
      security and unemployment
    
    1,046
    
    
    878
    
    
    750Other
    
    25
    
    
    338
    
    
    122Total
      general taxes
    $
    23,607
    
    $
    22,458
    
    $
    24,474**PROVISION
      FOR INCOME TAXES:**Currently
      payable-Federal
    $
    33,273
    
    $
    37,351
    
    $
    38,972State
    
    11,468
    
    
    11,368
    
    
    12,00444,741
    
    
    48,719
    
    
    50,976Deferred,
      net-Federal
    
    5,552
    
    
    (2,424
    )
    
    (4,144
    )State
    
    1,693
    
    
    (392
    )
    
    (1,193
    )7,245
    
    
    (2,816
    )
    
    (5,337
    )Investment
      tax credit amortization
    
    (2,234
    )
    
    (2,412
    )
    
    (2,595
    )Total
      provision for income taxes
    $
    49,752
    
    $
    43,491
    
    $
    43,044**INCOME
      STATEMENT CLASSIFICATION OF PROVISION FOR****INCOME
      TAXES:**Operating
      income
    $
    48,824
    
    $
    34,164
    
    $
    41,733Other
      income
    
    928
    
    
    1,795
    
    
    1,311Cumulative
      effect of accounting change
    
    --
    
    
    7,532
    
    
    --Total
      provision for income taxes
    $
    49,752
    
    $
    43,491
    
    $
    43,044**RECONCILIATION
      OF FEDERAL INCOME TAX EXPENSE AT****STATUTORY
      RATE TO TOTAL PROVISION FOR INCOME TAXES:**Book
      income before provision for income taxes
    $
    108,828
    
    $
    91,942
    
    $
    90,761Federal
      income tax expense at statutory rate
    $
    38,090
    
    $
    32,180
    
    $
    31,766Increases
      (reductions) in taxes resulting from:State
      income taxes, net of federal income tax benefit
    
    8,555
    
    
    7,134
    
    
    7,027Amortization
      of investment tax credits
    
    (2,234
    )
    
    (2,412
    )
    
    (2,595
    )Amortization
      of tax regulatory assets
    
    5,308
    
    
    5,616
    
    
    5,967Other,
      net
    
    33
    
    
    973
    
    
    879Total
      provision for income taxes
    $
    49,752
    
    $
    43,491
    
    $
    43,044**ACCUMULATED
      DEFERRED INCOME TAXES AT DECEMBER 31:**Competitive
      transition charge
    $
    18,862
    
    $
    37,280
    
    $
    56,172Property
      basis differences
    
    87,584
    
    
    77,147
    
    
    72,488Allowance
      for equity funds used during construction
    
    --
    
    
    --
    
    
    1,045Customer
      receivables for future income taxes
    
    1,471
    
    
    2,860
    
    
    4,249Unamortized
      investment tax credits
    
    (1,335
    )
    
    (1,457
    )
    
    (1,578
    )Deferred
      gain for asset sale to affiliated company
    
    7,451
    
    
    8,106
    
    
    8,810Other
      comprehensive income
    
    (9,707
    )
    
    (8,335
    )
    
    (7,045
    )Other
    
    (10,908
    )
    
    (17,730
    )
    
    (16,756
    )Net
      deferred income tax liability
    $
    93,418
    
    $
    97,871
    
    $
    117,385





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





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








19





**NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS**





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





The
consolidated financial statements include Penn (Company) and its wholly owned
subsidiary, Penn Power Funding LLC. The Company is a wholly owned subsidiary of
OE. The Company follows GAAP and complies with the regulations, orders, policies
and practices prescribed by the SEC, PPUC and FERC. OE is a wholly owned
subsidiary of FirstEnergy. 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. Certain 2003 revenues and expenses have been reclassified
and presented on a net basis to conform with the current year
presentation.





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 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 and Liabilities-*





The
Company recognizes, as regulatory assets, costs which the FERC and 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 rate restructuring plan. Based on the rate restructuring
plan, the Company continues to bill and collect cost-based rates relating to the
Company’s nongeneration operations and continues the application of SFAS 71 to
these operations.





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





**2004**
    
    **2003*****(In
      millions)***Competitive
      transition costs
    
    $
    46
    
    $
    90Customer
      receivables for future income taxes
    
    
    4
    
    
    7Loss
      on reacquired debt.
    
    
    7
    
    
    6Employee
      postretirement benefit costs
    
    
    1
    
    
    2Nuclear
      decommissioning costs
    
    
    (69
    )
    
    (72
    )Asset
      removal costs
    
    
    (7
    )
    
    (6
    )Other
    
    
    --
    
    
    1Net
      regulatory assets (liabilities)
    
    $
    (18
    )
    $
    28








20





Accounting
for Generation Operations-





The
application of SFAS 71 was discontinued in 1998 with respect to the Company's
generation operations. The SEC's interpretive guidance regarding asset
impairment measurement provided that any supplemental regulated cash flows such
as a CTC should be excluded from the cash flows of assets in a portion of the
business not subject to regulatory accounting practices. If those assets are
impaired, a regulatory asset should be established if the costs are recoverable
through regulatory cash flows. Consistent with the SEC guidance and EITF 97-4,
$227 million of impaired plant investments were recognized by the Company as
regulatory assets recoverable through a CTC over a seven-year transition period.
Net assets included in utility plant relating to the operations for which the
application of SFAS 71 was discontinued were $263 million as of
December 31, 2004.





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





All
temporary cash investments purchased with an initial maturity of three months or
less are reported as cash equivalents on the Consolidated Balance Sheets at
cost, which approximates their fair market value. Noncash financing and
investing activities included capital lease transactions amounting to $1.5
million for 2002. There were no capital lease transactions in 2004 and
2003.





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





The
Company's principal business is providing electric service to customers in
western 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
located in the Company’s service area 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 $44 million (billed - $28 million and unbilled - $16
million) and $45 million (billed - $29 million and unbilled - $16 million) as of
December 31, 2004 and 2003, respectively.





**(D)**
    **UTILITY
      PLANT AND DEPRECIATION-**





Utility
plant reflects original cost of construction (except for nuclear generating
units which were adjusted to fair value), including payroll and related costs
such as taxes, employee benefits, administrative and general costs, and interest
costs incurred to place the assets in service. The costs of normal maintenance,
repairs and minor replacements are expensed as incurred. 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 annual
composite rate for electric plant was approximately 2.2% in 2004 and 2003 and
2.3% in 2002.





*Jointly
- Owned Generating Stations-*





The
Company, together with OE and other affiliated companies, CEI and TE, own, as
tenants in common, various power generating facilities. Each of the companies is
obligated to pay a share of the costs associated with any jointly - owned
facility in the same proportion as its interest. The Company’s portion of
operating expenses associated with jointly - owned facilities is included in the
corresponding operating expenses on the Statements of Income. The amounts
reflected on the Consolidated Balance Sheet under utility plant as of
December 31, 2004 include the following:





**Utility**
    
    **Accumulated**
    
    **Construction**
    
    **Company's****Plant**
    
    **Provision
      for**
    
    **Work
      in**
    
    **Ownership****Generating
      Units**
    
    **in
      Service**
    
    **Depreciation**
    
    **Progress**
    
    **Interest*****(In
      millions)***W.
      H. Sammis Unit 7
    
    $
    64
    
    $
    24
    
    $
    --
    
    
    20.80
    %Bruce
      Mansfield Units 1, 2 and 3
    
    
    187
    
    
    102
    
    
    --
    
    
    16.38
    %Beaver
      Valley Units 1 and 2
    
    
    158
    
    
    27
    
    
    94
    
    
    39.37
    %Perry
    
    
    10
    
    
    2
    
    
    1
    
    
    5.24
    %Total
    
    $
    419
    
    $
    155
    
    $
    95





*Nuclear
Fuel-*





Nuclear
fuel is recorded at original cost, which includes material, enrichment,
fabrication and interest costs incurred prior to reactor load. The Company
amortizes the cost of nuclear fuel based on the units of production
method.





21





*Asset
Retirement Obligations-*





The
Company recognizes a liability for retirement obligations associated with
tangible assets in accordance with SFAS 143. This standard requires recognition
of the fair value of a liability for an ARO in the period in which it is
incurred. The associated asset retirement costs are capitalized as part of the
carrying value of the long-lived asset and depreciated over time, as described
further in Note 8, "Asset Retirement Obligations".





**(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.





*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 OE and preferred stockholders. As of December 31, 2004
and 2003, accumulated other comprehensive loss consisted of a minimum liability
for unfunded retirement benefits of $14 million and $12 million,
respectively.





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





Results
for 2003 include an after-tax credit to net income of $10.6 million recorded
upon the adoption of SFAS 143 in January 2003. The Company identified applicable
legal obligations as defined under the new standard for nuclear power plant
decommissioning and reclamation of a sludge disposal pond at the Bruce Mansfield
Plant. As a result of adopting SFAS 143 in January 2003, asset retirement costs
of $78 million were recorded as part of the carrying amount of the related
long-lived asset, offset by accumulated depreciation of $9 million. The ARO
liability at the date of adoption was $121 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 had recorded decommissioning
liabilities of $120 million. The Company expects substantially all of its
nuclear decommissioning costs to be recoverable in rates over time. Therefore,
it recognized a regulatory liability of $69 million upon adoption of SFAS 143
for the transition amounts subject to refund through rates related to the ARO
for nuclear decommissioning. The remaining cumulative effect adjustment for
unrecognized depreciation and accretion, offset by the reduction in the
liabilities and the reversal of accumulated estimated removal costs for
non-regulated generation assets, was an $18.2 million increase to income, or
$10.6 million net of income taxes. If SFAS 143 had been applied during 2002, the
impact would not have been material to the Company's Consolidated Statements of
Income.





**(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 åstand-aloneæ company basis, with the Company
recognizing any tax losses or credits it contributed to the consolidated
return.





22





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





Operating
revenues, operating expenses and other income include transactions with
affiliated companies, primarily ATSI, FES and FESC. FES operates the generation
businesses of the Company, OE, CEI and TE. As a result, the Company entered into
power supply agreements (PSA) whereby FES purchases all of the Company's nuclear
generation and the Company purchases its power from FES to meet its "provider of
last resort" obligations. In the fourth quarter of 2003, ATSI transferred
operational control of its transmission facilities to MISO and previously
affiliated transmission service expenses are now provided under the MISO Open
Access Transmission Tariff. In 2002, the Company terminated its nuclear fuel
leasing arrangement with OES Fuel and now owns its nuclear fuel. The primary
affiliated companies transactions are as follows:





**2004**
    
    **2003**
    
    **2002*****(In
      millions)*****Operating
      Revenues:**PSA
      revenues from FES
    
    $
    177
    
    $
    162
    
    $
    138Generating
      units rent from FES
    
    
    20
    
    
    20
    
    
    20Ground
      lease with ATSI
    
    
    1
    
    
    1
    
    
    1**Operating
      Expenses:**Nuclear
      fuel leased from OES Fuel
    
    
    --
    
    
    --
    
    
    5Purchased
      power under PSA
    
    
    181
    
    
    166
    
    
    157Transmission
      facilities rentals
    
    
    --
    
    
    10
    
    
    13FESC
      support services
    
    
    15
    
    
    13
    
    
    9**Other
      Income:**Interest
      income from ATSI
    
    
    3
    
    
    3
    
    
    3Interest
      income from FES
    
    
    --
    
    
    1
    
    
    1





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 Corp.
and a "mutual service company" as defined in Rule 93 of the PUHCA. The majority
of costs are directly billed or assigned at no more than cost as determined by
PUHCA Rule 91. The remaining costs are for services that are provided on behalf
of more than one company, or costs that cannot be precisely identified and are
allocated using formulas that are filed annually with the SEC on Form U-13-60.
The current allocation or assignment formulas used and their bases include
multiple factor formulas; each company’s proportionate amount of FirstEnergy’s
aggregate direct payroll, number of employees, asset balances, revenues, number
of customers, other factors and specific departmental charge ratios. Management
believes that these allocation methods are reasonable. Intercompany transactions
with OE, FirstEnergy and its other subsidiaries are generally settled under
commercial terms within thirty days, except for $4 million payable to affiliates
for OPEB obligations.





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





FirstEnergy
provides noncontributory defined benefit pension plans that cover substantially
all of its employees. The trusteed plans provide defined benefits based on years
of service and compensation levels. The Company's funding policy is based on
actuarial computations using the projected unit credit method. In the third
quarter of 2004, FirstEnergy made a $500 million voluntary contribution to its
pension plan (Company's share was $13 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 (Company's
share was $8 million).





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





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





23





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
    
    $
    23
    
    $
    10
    
    $
    (43
    )
    $
    (39
    )Increase
      (decrease) in minimum liabilityIncluded
      in other comprehensive income(net
      of tax)
    
    $
    (4
    )
    $
    (145
    )
    
    --
    
    
    --**Assumptions
      Used to Determine**
      **Benefit
      Obligations As of December 31**Discount
      rate
    
    
    6.00
    %
    
    6.25
    %
    
    6.00
    %
    
    6.25
    %Rate
      of compensation increase
    
    
    3.50
    %
    
    3.50
    %





**Allocation
      of Plan Assets**
      **As
      of December 31**Asset
      CategoryEquity
      securities
    
    
    68
    %
    
    70
    %
    
    74
    %
    
    71
    %Debt
      securities
    
    
    29
    
    
    27
    
    
    25
    
    
    22Real
      estate
    
    
    2
    
    
    2
    
    
    --
    
    
    --Cash
    
    
    1
    
    
    1
    
    
    1
    
    
    7Total
    
    
    100
    %
    
    100
    %
    
    100
    %
    
    100
    %





**Information
      for Pension Plans With an**
      **Accumulated
      Benefit Obligation in****Excess
      of Plan Assets**
    
    **2004**
    
    **2003*****(In
      millions)***Projected
      benefit obligation
    
    $
    4,364
    
    $
    4,162Accumulated
      benefit obligation
    
    
    3,983
    
    
    3,753Fair
      value of plan assets
    
    
    3,969
    
    
    3,315








24








**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
    
    $
    --
    
    $
    4
    
    $
    1
    
    $
    5
    
    $
    7
    
    $
    2





**Weighted-Average
      Assumptions Used****to
      Determine Net Periodic Benefit Cost**
    
    **Pension
      Benefits**
    
    **Other
      Benefits****for
      Years Ended December 31**
    
    **2004**
    
    **2003**
    
    **2002**
    
    **2004**
    
    **2003**
    
    **2002**Discount
      rate
    
    
    6.25
    %
    
    6.75
    %
    
    7.25
    %
    
    6.25
    %
    
    6.75
    %
    
    7.25
    %Expected
      long-term return on plan assets
    
    
    9.00
    %
    
    9.00
    %
    
    10.25
    %
    
    9.00
    %
    
    9.00
    %
    
    10.25
    %Rate
      of compensation increase
    
    
    3.50
    %
    
    3.50
    %
    
    4.00
    %





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





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





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





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





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





Pursuant
to FSP 106-1 issued January 12, 2004, FirstEnergy began accounting for the
effects of the Medicare Act effective January 1, 2004 because of a plan
amendment during the quarter, which required remeasurement of the plan's
obligations. T he plan
amendment, which increases cost-sharing by employees and retirees effective
January 1, 2005, reduced the Company's postretirement benefit costs by $2
million during 2004.





Consistent
with the guidance in FSP 106-2 issued on May 19, 2004, FirstEnergy
recognized a reduction of $318 million in the accumulated postretirement benefit
obligation as a result of the federal subsidy provided under the Medicare Act
related to benefits for past service. This reduction was accounted for as an
actuarial gain in 2004 pursuant to FSP 106-2. The subsidy reduced the Company's
net periodic postretirement benefit costs by $2 million during
2004.





25





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 $8 million. As prescribed by SFAS 87, the Company
increased its additional minimum liability by $4 million, recording an increase
in an intangible asset of $1 million and charging $3 million to OCI. The balance
in AOCL of $14 million (net of $10 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
    
    $
    148
    
    $
    160
    
    $
    211
    
    $
    228Preferred
      stock subject to mandatory redemption
    
    
    13
    
    
    12
    
    
    14
    
    
    14$
    161
    
    $
    172
    
    $
    225
    
    $
    242





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
    
    $
    41
    
    $
    41
    
    $
    47
    
    $
    47-Corporate
      debt securities
    
    
    77
    
    
    83
    
    
    76
    
    
    81-Mortgage-backed
      securities
    
    
    1
    
    
    1
    
    
    --
    
    
    --119
    
    
    125
    
    
    123
    
    
    128Equity
      securities(1)
    
    
    57
    
    
    57
    
    
    52
    
    
    52$
    176
    
    $
    182
    
    $
    175
    
    $
    180


(1)  Includes
nuclear decommissioning trust investments.





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





26





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
    
    $
    85
    
    $
    2
    
    $
    1
    
    $
    86
    
    $
    82
    
    $
    2
    
    $
    --
    
    $
    84Equity
      securities
    
    
    50
    
    
    8
    
    
    1
    
    
    57
    
    
    47
    
    
    5
    
    
    2
    
    
    50$
    135
    
    $
    10
    
    $
    2
    
    $
    143
    
    $
    129
    
    $
    7
    
    $
    2
    
    $
    134





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
    
    $
    41
    
    $
    47
    
    $
    53Gross
      realized gains
    
    
    1
    
    
    2
    
    
    2Gross
      realized losses
    
    
    1
    
    
    1
    
    
    3Interest and
      dividend income
    
    
    5
    
    
    5
    
    
    5
   
 The following table
provides the fair value and gross unrealized losses of nuclear decommissioning
trust investments that are deemed to be temporarily impaired as of
December 31, 2004.





**Less
      Than 12 Months**
    
    **12
      Months or More**
    
    **Total****Fair**
    
    **Unrealized**
    
    **Fair**
    
    **Unrealized**
    
    **Fair**
    
    **Unrealized****Value**
    
    **Losses**
    
    **Value**
    
    **Losses**
    
    **Value**
    
    **Losses*****(In
      millions)***Debt
      securities
    
    $
    30
    
    $
    --
    
    $
    3
    
    $
    1
    
    $
    33
    
    $
    1Equity
      securities
    
    
    --
    
    
    --
    
    
    13
    
    
    1
    
    
    13
    
    
    1$
    30
    
    $
    --
    
    $
    16
    
    $
    2
    
    $
    46
    
    $
    2





The
Company periodically evaluates the securities held by its nuclear
decommissioning trusts for other-than-temporary impairment. The Company
considers the length of time and the extent to which the security's fair value
has been less than its cost basis and other factors to determine whether an
impairment is other than temporary. The Company's decommissioning trusts are
subject to regulatory accounting in accordance with SFAS 71. Net unrealized
gains and losses are recorded as regulatory liabilities or assets since the
difference between investments held in trust and the decommissioning liabilities
are recovered from or refunded to customers.





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





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





The
Company leases office space and other property and equipment under cancelable
and noncancelable leases. Consistent with the regulatory treatment, the rentals
for capital and operating leases are charged to operating expenses on the
Statements of Income. Such costs for the three years ended December 31,
2004, are summarized as follows:





**2004**
    
    **2003**
    
    **2002*****(In
      millions)***Operating
      leasesInterest
      element
    
    $
    0.3
    
    $
    0.2
    
    $
    0.1Other
    
    
    0.6
    
    
    0.3
    
    
    0.2Capital
      leasesInterest
      element
    
    
    --
    
    
    --
    
    
    --Other
    
    
    --
    
    
    --
    
    
    0.1Total
      rentals
    
    $
    0.9
    
    $
    0.5
    
    $
    0.4





27








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





**Operating****Leases*****(In
      millions)***2005
    
    $
    0.12006
    
    
    0.12007
    
    
    0.12008
    
    
    0.12009
    
    
    0.1Years
      thereafter
    
    
    0.5Total
      minimum lease payments
    
    $
    1.0





**6.**
    **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. No procedural
schedule or hearing date has been set for this proceeding. The Company 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 Penelec 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.





28








Pennsylvania
enacted its electric utility competition law in 1996 with the phase in of
customer choice for electric generation suppliers completed as of
January 1, 2001. The Company continues to deliver power to homes and
businesses through its distribution system, which remains regulated by the PPUC.
The Company’s rates have been restructured to itemize (unbundle) the current
price of electricity into its component elements - including generation,
transmission, distribution and stranded cost recovery. In the event customers
obtain power from an alternative source, the generation portion of the Company’s
rates is excluded from their bill and the customers receive a generation charge
from the alternative supplier. The stranded cost recovery portion of rates
provides for recovery of certain amounts not otherwise considered recoverable in
a competitive generation market, including regulatory assets. Under the rate
restructuring plan, the Company is entitled to recover $236 million of stranded
costs through the CTC that began in 1999 and ends in 2006.





**7.**
    **CAPITALIZATION:**





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





Under
the Company’s Charter, the Company’s retained earnings unrestricted for payment
of cash dividends on the Company’s common stock were $78.0 million as of
December 31, 2004.





**(B)**
    **PREFERRED
      STOCK-**





All
preferred stock may be redeemed by the Company in whole, or in part, with 30-60
days’ notice.





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





*Preferred
Stock Subject to Mandatory Redemption-*





The
Company’s 7.625% series has an annual sinking fund requirement for 7,500 shares
in 2005 and 2006.





The Company's preferred shares are retired at $100 per share plus accrued
dividends. Annual sinking fund requirements are $750,000 in 2005 and 2006 and
$11.25 million in 2007.





*Other
Long-Term Debt-*





The
Company has a FMB indenture under which it issues FMB secured by a direct first
mortgage lien on substantially all of its property and franchises, other than
specifically excepted property. The Company has various debt covenants under its
financing arrangements. The most restrictive of the debt covenants relate to the
nonpayment of interest and/or principal on debt which could trigger a default
and the maintenance of minimum fixed charge ratios and debt to capitalization
ratios. There also exists cross-default provisions among financing arrangements
of FirstEnergy and the Company.


Based on
the amount of FMB authenticated by the mortgage bond trustee through
December 31, 2004, the Company's annual sinking fund requirements for all
FMB issued under its first mortgage indenture amounts to $10 million. The
Company expects to deposit funds with its mortgage bond trustee in 2005 that
will then be withdrawn upon the surrender for cancellation of a like principal
amount of FMB, which are specifically authenticated for such purposes against
unfunded property additions or against previously retired FMB. This method can
result in minor increases in the amount of the annual sinking fund
requirement.





Sinking
fund requirements for FMB and maturing long-term debt during the next five years
are $26 million in 2005 and $1.0 million in each year 2006 through 2009.
Included in these amounts are various variable interest rate long-term debt
which have provisions by which individual debt holders have the option to "put
back" or require the respective debt issuer to redeem their debt at those times
when the interest rate may change prior to its maturity date. Those amounts are
$25 million in 2005, which represents the next time the debt holders may
exercise this provision.





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 irrevocable bank LOCs of $10.4 million and
noncancelable municipal bond insurance policies of $38 million to pay
principal of, or interest on, the pollution control revenue bonds. To the extent
that drawings are made under the LOCs or policies, the Company is entitled to a
credit against its obligation to repay the related bond. The Company pays an
annual fee of 1.0% of the amount of the LOCs to the issuing bank and 0.24% to
0.30% of the amounts of the policies to the insurers and is obligated to
reimburse the bank or insurers, as the case may be, for any drawings
thereunder.





29








**8.**
    **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 and reclamation of a sludge
disposal pond related to the Bruce Mansfield Plant. The ARO liability as of the
date of adoption of SFAS 143 was $121.3 million, including accumulated accretion
for the period from the date the liability was incurred to the date of adoption.
Accretion during 2004 was $8 million, bringing the ARO liability as of
December 31, 2004 to $138 million. The ARO includes the Company's
obligation for nuclear decommissioning of the Beaver Valley and Perry generating
facilities. The Company's share of the obligation to decommission these units
was developed based on site-specific studies 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 $143 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
    
    $
    130
    
    $
    122Accretion
    
    
    8
    
    
    8Ending
      balance as of December 31
    
    $
    138
    
    $
    130





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
    
    $
    114Accretion
    
    
    8Ending
      balance as of December 31
    
    $
    122





**9.**
    **SHORT-TERM
      BORROWINGS:**





The
Company may borrow from affiliates on a short-term basis. As of
December 31, 2004, the Company had borrowed $11.9 million from its
affiliates at an average interest rate of 2.0%.





In March
2004, the Company completed, through a separate wholly owned subsidiary, a
receivables financing arrangement that provides borrowing capability of up to
$25 million. The borrowing rate is based on bank commercial paper rates. The
Company is required to pay an annual facility fee of 0.40% on the entire finance
limit. The facility was undrawn as of December 31, 2004 and matures on
March 29, 2005. This receivables financing arrangement is expected to be
renewed prior to expiration.





**10.**
    **COMMITMENTS
      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 ownership interests in the Beaver Valley Station and the Perry
Plant, the Company’s maximum potential assessment under the industry
retrospective rating plan (assuming the other affiliate co-owners contribute
their proportionate shares of any assessments under the retrospective rating
plan) would be $84.5 million per incident but not more than $8.4 million in
any one year for each incident.





30








The
Company is also insured as to its interest in Beaver Valley and Perry under
policies issued to the operating company for each plant. Under these policies,
up to $2.75 billion is provided for property damage and decontamination and
decommissioning costs. The Company has also obtained approximately
$280.1 million of insurance coverage for replacement power costs for its
interests in Beaver Valley and Perry. Under these policies, the Company can be
assessed a maximum of approximately $13.2 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 replacement power, property
damage, decontamination, decommissioning, repair and replacement costs and other
such costs arising from a nuclear incident at any of the Company’s plants exceed
the policy limits of the insurance in effect with respect to that plant, to the
extent a nuclear incident is determined not to be covered by the 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-**





Various
federal, state and local authorities regulate the Company with regard to air and
water quality and other environmental matters. The effects of compliance on the
Company with regard to environmental matters could have a material adverse
effect on the Company's earnings and competitive position. These environmental
regulations affect the Company's earnings and competitive position to the extent
that it competes with companies that are not subject to such regulations and
therefore do not bear the risk of costs associated with compliance, or failure
to comply, with such regulations. Overall, the Company believes it is in
material compliance with existing regulations but is unable to predict future
change in regulatory policies and what, if any, the effects of such change would
be. Generation operations and any related additional capital expenditures for
environmental compliance are the responsibility of FirstEnergy's competitive
services business unit.





*Clean
Air Act Compliance-*


The
Company is required to meet federally approved SO2regulations. Violations of such regulations can result in shutdown of the
generating unit involved and/or civil or criminal penalties of up to $32,500 for
each day the unit is in violation. The EPA has an interim enforcement policy for
SO2regulations in Ohio that allows for compliance based on a 30-day averaging
period. The Company cannot predict what action the EPA may take in the future
with respect to the interim enforcement policy.


The
Company believes it is complying with SO2reduction requirements under the Clean Air Act Amendments of 1990 by burning
lower-sulfur fuel, generating more electricity from lower-emitting plants,
and/or using emission allowances. NOxreductions required by the 1990 Amendments are being achieved through combustion
controls and the generation of more electricity at lower-emitting plants. In
September 1998, the EPA finalized regulations requiring additional
NOxreductions from the Company's facilities. The EPA's NOxTransport Rule imposes uniform reductions of NOxemissions (an approximate 85% reduction in utility plant NOxemissions from projected 2007 emissions) across a region of nineteen states
(including Ohio and Pennsylvania) and the District of Columbia based on a
conclusion that such NOxemissions
are contributing significantly to ozone levels in the eastern United States. The
Company believes its facilities are complying with the NOxbudgets
established under State Implementation Plans (SIPs) through combustion controls
and post-combustion controls, including Selective Catalytic Reduction and
Selective Non-Catalytic Reduction systems, and/or using emission
allowances.


*National
Ambient Air Quality Standards-*





In July
1997, the EPA promulgated changes in the NAAQS for ozone and proposed a new
NAAQS for fine particulate matter. On December 17, 2003, the EPA proposed
the "Interstate Air Quality Rule" covering a total of 29 states (including Ohio
and Pennsylvania) and the District of Columbia based on proposed findings that
air pollution emissions from 29 eastern states and the District of Columbia
significantly contribute to nonattainment of the NAAQS for fine particles and/or
the "8-hour" ozone NAAQS in other states. The EPA has proposed the Interstate
Air Quality Rule to "cap-and-trade" NO x and
SO 2 emissions in two phases (Phase I in 2010 and Phase II in 2015). According to the
EPA, SO 2 emissions would be reduced by approximately 3.6 million tons annually by 2010,
across states covered by the rule, with reductions ultimately reaching more than
5.5 million tons annually. NO x emission reductions would measure about 1.5 million tons in 2010 and 1.8 million
tons in 2015. The future cost of compliance with these proposed regulations may
be substantial and will depend on whether and how they are ultimately
implemented by the states in which the Company operates affected facilities.





31








*Mercury
Emissions-*





In
December 2000, the EPA announced it would proceed with the development of
regulations regarding hazardous air pollutants from electric power plants,
identifying mercury as the hazardous air pollutant of greatest concern. On
December 15, 2003, the EPA proposed two different approaches to reduce
mercury emissions from coal-fired power plants. The first approach would require
plants to install controls known as MACT based on the type of coal burned.
According to the EPA, if implemented, the MACT proposal would reduce nationwide
mercury emissions from coal-fired power plants by 14 tons to approximately 34
tons per year. The second approach proposes a cap-and-trade program that would
reduce mercury emissions in two distinct phases. Initially, mercury emissions
would be reduced by 2010 as a "co-benefit" from implementation of SO2and
NOxemission
caps under the EPA's proposed Interstate Air Quality Rule. Phase II of the
mercury cap-and-trade program would be implemented in 2018 to cap nationwide
mercury emissions from coal-fired power plants at 15 tons per year. The EPA has
agreed to choose between these two options and issue a final rule by
March 15, 2005. The future cost of compliance with these regulations may be
substantial.





*W.
H. Sammis Plant-*





In 1999
and 2000, the EPA issued NOV or Compliance Orders to nine utilities covering 44
power plants, including the W. H. Sammis Plant, which is owned by the Company
and OE. In addition, the U.S. Department of Justice filed eight civil complaints
against various investor-owned utilities, which included a complaint against the
Company and OE in the U.S. District Court for the Southern District of Ohio.
These cases are referred to as New Source Review cases. The NOV and complaint
allege violations of the Clean Air Act based on operation and maintenance of the
W. H. Sammis Plant dating back to 1984. The complaint requests permanent
injunctive relief to require the installation of "best available control
technology" and civil penalties of up to $27,500 per day of violation. On
August 7, 2003, the United States District Court for the Southern District
of Ohio ruled that 11 projects undertaken at the W. H. Sammis Plant between 1984
and 1998 required pre-construction permits under the Clean Air Act. The ruling
concludes the liability phase of the case, which deals with applicability of
Prevention of Significant Deterioration provisions of the Clean Air Act. The
remedy phase trial to address civil penalties and what, if any, actions should
be taken to further reduce emissions at the plant has been delayed without
rescheduling by the Court because the parties are engaged in meaningful
settlement negotiations. The Court indicated, in its August 2003 ruling, that
the remedies it "may consider and impose involved a much broader, equitable
analysis, requiring the Court to consider air quality, public health, economic
impact, and employment consequences. The Court may also consider the less than
consistent efforts of the EPA to apply and further enforce the Clean Air Act."
The potential penalties that may be imposed, as well as the capital expenditures
necessary to comply with substantive remedial measures that may be required,
could have a material adverse impact on FirstEnergy's, the Company's and OE's
respective financial condition and results of operations. While the parties are
engaged in meaningful settlement discussions, management is unable to predict
the ultimate outcome of this matter and no liability has been accrued as of
December 31, 2004.





*Regulation
of Hazardous Waste-*





As a
result of the Resource Conservation and Recovery Act of 1976, as amended, and
the Toxic Substances Control Act of 1976, federal and state hazardous waste
regulations have been promulgated. Certain fossil-fuel combustion waste
products, such as coal ash, were exempted from hazardous waste disposal
requirements pending the EPA's evaluation of the need for future regulation. The
EPA subsequently determined that regulation of coal ash as a hazardous waste is
unnecessary. In April 2000, the EPA announced that it will develop national
standards regulating disposal of coal ash under its authority to regulate
nonhazardous waste.





*Climate
Change-*





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





The
Company cannot currently estimate the financial impact of climate change
policies, although the potential restrictions on CO2emissions could require significant capital and other expenditures. However, the
CO2emissions per kilowatt-hour of electricity generated by the Company is lower
than many regional competitors due to the Company's diversified generation
sources which includes low or non-CO2emitting gas-fired and nuclear generators.





32





*Clean
Water Act-*





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





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





**(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 Note 6). FirstEnergy’s implementation of these recommendations
included completion of the Task Force recommendations that were directed toward
FirstEnergy. As many of these initiatives already were in process, FirstEnergy
does not believe that any incremental expenses associated with additional
initiatives undertaken during 2004 will have a material effect on its operations
or financial results. FirstEnergy notes, however, that the applicable government
agencies and reliability coordinators may take a different view as to
recommended enhancements or may recommend additional enhancements in the future
that could require additional, material expenditures. FirstEnergy has not
accrued a liability as of December 31, 2004 for any expenditures in excess
of those actually incurred through that date.





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





*Legal
Matters-*





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





On
August 12, 2004, the NRC notified FENOC that it will increase its regulatory
oversight of the Perry Nuclear Power Plant as a result of problems with safety
system equipment over the past two years. FENOC operates the Perry Nuclear Power
Plant, in which the Company owns a 5.24% interest. Although the NRC
noted that the plant continues to operate safely, the agency has indicated that
its increased oversight will include an extensive NRC team inspection to assess
the equipment problems and the sufficiency of FENOC's corrective actions. The
outcome of these matters could include NRC enforcement action or other impacts
on operating authority. As a result, these matters could have a material adverse
effect on FirstEnergy's or its subsidiaries' financial condition.





33








**11.**
    **NEW
      ACCOUNTING STANDARDS AND INTERPRETATIONS:**





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





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





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





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





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





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





*EITF
      Issue No. 03-16, "Accounting for Investments in Limited Liability
      Companies"*


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







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





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





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





Issued
in May 2004, FSP 106-2 provides guidance on accounting for the effects of the
Medicare Act for employers that sponsor postretirement health care plans that
provide prescription drug benefits. FSP 106-2 also requires certain disclosures
regarding the effect of the federal subsidy provided by the Medicare Act. The
effect of the federal subsidy provided under the Medicare Act on the Company's
consolidated financial statements is described in Note 3.





34








**12.**
    **SUMMARY
      OF QUARTERLY FINANCIAL DATA (UNAUDITED):**





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








**March
      31,**
    
    **June
      30,**
    
    **September
      30,**
    
    **December
      31,****Three
      Months Ended**
    
    **2004**
    
    **2004**
    
    **2004**
    
    **2004*****(In
      millions)***Operating
      Revenues
    
    $
    142.6
    
    $
    134.6
    
    $
    143.3
    
    $
    128.6Operating
      Expenses and Taxes
    
    
    122.1
    
    
    115.4
    
    
    123.1
    
    
    127.7Operating
      Income
    
    
    20.5
    
    
    19.2
    
    
    20.2
    
    
    0.9Other
      Income
    
    
    1.0
    
    
    0.5
    
    
    0.8
    
    
    1.2Net
      Interest Charges
    
    
    1.8
    
    
    1.8
    
    
    0.6
    
    
    1.0Net
      Income
    
    $
    19.7
    
    $
    17.9
    
    $
    20.4
    
    $
    1.1Earnings
      on Common Stock
    
    $
    19.1
    
    $
    17.3
    
    $
    19.7
    
    $
    0.4





**March
      31,**
    
    **June
      30,**
    
    **September
      30,**
    
    **December
      31,****Three
      Months Ended**
    
    **2003**
    
    **2003**
    
    **2003**
    
    **2003*****(In
      millions)***Operating
      Revenues
    
    $
    128.3
    
    $
    116.6
    
    $
    145.8
    
    $
    135.8Operating
      Expenses and Taxes
    
    
    130.2
    
    
    110.3
    
    
    125.9
    
    
    112.8Operating
      Income (Loss)
    
    
    (1.9
    )
    
    6.3
    
    
    19.9
    
    
    23.0Other
      Income
    
    
    0.6
    
    
    0.5
    
    
    0.4
    
    
    1.3Net
      Interest Charges
    
    
    3.4
    
    
    3.4
    
    
    2.9
    
    
    2.5Income
      (Loss) Before Cumulative Effect of Accounting Change
    
    
    (4.7
    )
    
    3.4
    
    
    17.4
    
    
    21.8Cumulative
      Effect of Accounting Change (Net of Income Taxes)
    
    
    10.6
    
    
    --
    
    
    --
    
    
    --Net
      Income
    
    $
    5.9
    
    $
    3.4
    
    $
    17.4
    
    $
    21.8Earnings
      on Common Stock
    
    $
    5.0
    
    $
    2.5
    
    $
    16.8
    
    $
    21.1







35