**THE TOLEDO
EDISON COMPANY**
 
 **2004 ANNUAL
REPORT TO STOCKHOLDERS**
 
 
 
 The Toledo Edison
Company (TE) is a wholly owned electric utility operating subsidiary of
FirstEnergy Corp. It engages in the generation, distribution and sale of
electric energy in an area of approximately 2,500 square miles in northwestern
Ohio. The area it serves has a population of approximately 0.8
million.
 
 
 
 
 
 
 
 **Contents**
    **Page**Glossary of
      Terms
    i-iiManagement
      Reports
    1Report of
      Independent Registered Public Accounting Firm
    2Selected
      Financial Data
    3Management's
      Discussion and Analysis
    4-16Consolidated
      Statements of Income
    17Consolidated
      Balance Sheets
    18Consolidated
      Statements of Capitalization
    19Consolidated
      Statements of Common Stockholder's Equity
    20Consolidated
      Statements of Preferred Stock
    20Consolidated
      Statements of Cash Flows
    21Consolidated
      Statements of Taxes
    22Notes to
      Consolidated Financial Statements
    23-43
 
  
  **GLOSSARY OF
TERMS**
 
 The following
abbreviations and acronyms are used in this report to identify The Toledo Edison
Company and its affiliates:
 
 ATSI
    American
      Transmission Systems, Inc., owns and operates transmission
      facilitiesCEI
    The Cleveland
      Electric Illuminating Company, an affiliated Ohio electric utilityCFC
    Centerior
      Funding Corporation, a wholly owned finance subsidiary of
    CEICompanies
    OE, CEI, TE,
      Penn, JCP&L, Met-Ed and PenelecFENOC
    FirstEnergy
      Nuclear Operating Company, operates nuclear generating
      facilitiesFES
    FirstEnergy
      Solutions Corp., provides energy-related products and
    servicesFESC
    FirstEnergy
      Service Company, provides legal, financial, and other corporate support
      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, an affiliated Ohio electric utilityPenelec
    Pennsylvania
      Electric Company, an affiliated Pennsylvania electric utilityPenn
    Pennsylvania
      Power Company, an affiliated Pennsylvania electric
  utilityShippingport
    Shippingport
      Capital Trust, a special purpose entity created by CEI and TE in
      1997TE
    The Toledo
      Edison CompanyTECC
    Toledo Edison
      Capital Corporation, a 90% owned subsidiary of TEThe following
      abbreviations and acronyms are used to identify frequently used terms in
      this report:AOCL
    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 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 CommissionFIN
      46R
    FASB
      Interpretation No. 46 (revised December 2003), "Consolidation of Variable
      Interest Entities"FMB
    First
      Mortgage BondsFSP
    FASB Staff
      PositionFSP EITF
      03-1-1
    FASB Staff
      Position No. EITF Issue 03-1-1, "Effective Date of Paragraphs 10-20 of
      EITF Issue
      No. 03-1, The
      Meaning of Other-Than-Temporary Impairment and Its Application to
      Certain
      Investments"FSP
      106-1
    FASB Staff
      Position No.106-1, "Accounting and Disclosure Requirements Related to the
      Medicare
      Prescription
      Drug, Improvement and Modernization Act of 2003"FSP
      106-2
    FASB Staff
      Position No.106-2, "Accounting and Disclosure Requirements Related to
      the
      Medicare
      Prescription Drug, 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-hoursMACT
    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 ServiceMW
    Megawatts
 
   i
 
 **GLOSSARY OF
TERMS Cont.**
   NAAQS
    National
      Ambient Air Quality StandardsNERC
    North
      American Electric Reliability CouncilNOAC
    Northwest
      Ohio Aggregation CoalitionNOX
    Nitrogen
      OxideNRC
    Nuclear
      Regulatory CommissionOCC
    Ohio
      Consumers' CounselOCI
    Other
      Comprehensive IncomeOPEB
    Other
      Post-Employment BenefitsPJM
    PJM
      Interconnection L. L. C.PRP
    Potentially
      Responsible PartyPUCO
    Public
      Utilities Commission of OhioPUHCA
    Public
      Utility Holding Company ActRTC
    Regulatory
      Transition ChargeS&P
    Standard
      & Poor’s Ratings ServiceSEC
    United States
      Securities and Exchange CommissionSFAS
    Statement of
      Financial Accounting StandardsSFAS
      71
    SFAS No. 71,
      "Accounting for the Effects of Certain Types of
  Regulation"SFAS
      87
    SFAS No. 87,
      "Employers' Accounting for Pensions"SFAS
      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
      140
    SFAS No. 140,
      "Accounting for Transfers and Servicing of Financial Assets and
      Extinguishment
      of Liabilities"SFAS
      142
    SFAS No. 142,
      "Goodwill and Other Intangible Assets"SFAS
      143
    SFAS No. 143,
      "Accounting for Asset Retirement Obligations"SFAS
      144
    SFAS No. 144,
      "Accounting for the Impairment or Disposal of Long-Lived
      Assets"SO2
    Sulfur
      DioxideVIE
    Variable
      Interest Entity
 
   
   
   ii
   **MANAGEMENT
REPORTS**
 
 *Management's
Responsibility for Financial Statements*
 
 The consolidated
financial statements were prepared by management, who takes responsibility for
their integrity and objectivity. The statements were prepared in conformity with
accounting principles generally accepted in the United States and are consistent
with other financial information appearing elsewhere in this report.
PricewaterhouseCoopers LLP, an independent registered public accounting firm,
has expressed an unqualified opinion on the Company’s 2004 consolidated
financial statements.
 
 FirstEnergy Corp.’s
internal auditors, who are responsible to the Audit Committee of FirstEnergy’s
Board of Directors, review the results and performance of operating units within
the Company for adequacy, effectiveness and reliability of accounting and
reporting systems, as well as managerial and operating controls.
 
 FirstEnergy’s Audit
Committee consists of five independent directors whose duties include:
consideration of the adequacy of the internal controls of the Company and the
objectivity of financial reporting; inquiry into the number, extent, adequacy
and validity of regular and special audits conducted by independent auditors and
the internal auditors; and reporting to the Board of Directors the Committee’s
findings and any recommendation for changes in scope, methods or procedures of
the auditing functions. The Committee is directly responsible for appointing the
Company’s independent registered public accounting firm and is charged with
reviewing and approving all services performed for the Company by the
independent registered public accounting firm and for reviewing and approving
the related fees. The Committee reviews the independent registered public
accounting firm’s report on internal quality control and reviews all
relationships between the independent registered public accounting firm and the
Company, in order to assess the registered public accounting firm’s
independence. The Committee also reviews management’s programs to monitor
compliance with the Company’s policies on business ethics and risk management.
The Committee establishes procedures to receive and respond to complaints
received by the Company regarding accounting, internal accounting controls, or
auditing matters and allows for the confidential, anonymous submission of
concerns by employees. The Audit Committee held six meetings in
2004.
 
 *Management's
Report on Internal Control Over Financial Reporting*
 
 Management is
responsible for establishing and maintaining adequate internal control over
financial reporting as defined in Rule 13a-15(f) of the Securities Exchange Act
of 1934. Using the criteria set forth by the Committee of Sponsoring
Organizations of the Treadway Commission in *Internal
Control - Integrated Framework* , management
conducted an evaluation of the effectiveness of the Company’s internal control
over financial reporting under the supervision of the chief executive officer
and the chief financial officer. Based on that evaluation, management concluded
that the Company’s internal control over financial reporting was effective as of
December 31, 2004 *.* Management’s
assessment of the effectiveness of the Company’s internal control over financial
reporting, as of December 31, 2004, has been audited by
PricewaterhouseCoopers LLP, an independent registered public accounting firm, as
stated in their report which appears on page 2.
 
 
 
   1
   **Report of
Independent Registered Public Accounting Firm**
 
 
 To the Stockholders
and Board of
 Directors of The
Toledo Edison Company:
 
 We have completed
an integrated audit of The Toledo Edison Company’s 2004 consolidated financial
statements and of its internal control over financial reporting as of December
31, 2004 and audits of its 2003 and 2002 consolidated financial statements in
accordance with the standards of the Public Company Accounting Oversight Board
(United States). Our opinions, based on our audits, are presented
below.
 
 Consolidated
financial statements
 
 In our opinion, the
accompanying consolidated balance sheets and the related consolidated statements
of income, capitalization, common stockholder’s equity, preferred stock, cash
flows and taxes present fairly, in all material respects, the financial position
of The Toledo Edison 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. As
discussed in Note 6 to the consolidated financial statements, the Company
changed its method of accounting for the consolidation of variable interest
entities as of December 31, 2003.
 
 Internal control
over financial reporting
 
 Also, in our
opinion, management’s assessment, included in the accompanying Management Report
on Internal Control Over Financial Reporting, that the Company maintained
effective internal control over financial reporting as of December 31, 2004
based on criteria established in Internal Control - Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway Commission (COSO),
is fairly stated, in all material respects, based on those criteria.
Furthermore, in our opinion, the Company maintained, in all material respects,
effective internal control over financial reporting as of December 31, 2004,
based on criteria established in Internal Control - Integrated Framework issued
by the COSO. The Company’s management is responsible for maintaining effective
internal control over financial reporting and for its assessment of the
effectiveness of internal control over financial reporting. Our responsibility
is to express opinions on management’s assessment and on the effectiveness
of the Company’s internal control over financial reporting based on our audit.
We conducted our audit of internal control over financial reporting in
accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether effective internal control over
financial reporting was maintained in all material respects. An audit of
internal control over financial reporting includes obtaining an understanding of
internal control over financial reporting, evaluating management’s assessment,
testing and evaluating the design and operating effectiveness of internal
control, and performing such other procedures as we consider necessary in the
circumstances. We believe that our audit provides a reasonable basis for our
opinions.
 
 A company’s
internal control over financial reporting is a process designed to provide
reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with
generally accepted accounting principles. A company’s internal control over
financial reporting includes those policies and procedures that (i) pertain
to the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company;
(ii) provide reasonable assurance that transactions are recorded as
necessary to permit preparation of financial statements in accordance with
generally accepted accounting principles, and that receipts and expenditures of
the company are being made only in accordance with authorizations of management
and directors of the company; and (iii) provide reasonable assurance
regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a material effect on the
financial statements.
 
 Because of its
inherent limitations, internal control over financial reporting may not prevent
or detect misstatements. Also, projections of any evaluation of effectiveness to
future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the
policies or procedures may deteriorate.
 
 
 PricewaterhouseCoopers
LLP
 Cleveland,
Ohio
 March 7,
2005
 
 
 
 2
 ****
 **THE TOLEDO
EDISON COMPANY**
 
 **SELECTED
FINANCIAL DATA**
 
 
 
 **2004**
    
    **2003**
    
    **2002**
    
    **2001**
    
    **2000*****(Dollars
      in thousands)*****GENERAL
      FINANCIAL INFORMATION:**Operating
      Revenues
    
    $
    1,008,112
    
    $
    932,335
    
    $
    996,045
    
    $
    1,086,503
    
    $
    954,947Operating
      Income
    
    $
    93,075
    
    $
    35,660
    
    $
    36,699
    
    $
    85,964
    
    $
    194,325Income (Loss)
      Before Cumulative Effect of
      Accounting
      Change
    
    $
    86,283
    
    $
    19,930
    
    $
    (5,142
    )
    $
    42,691
    
    $
    138,144Net Income
      (Loss)
    
    $
    86,283
    
    $
    45,480
    
    $
    (5,142
    )
    $
    42,691
    
    $
    138,144Earnings
      (Loss) on Common Stock
    
    $
    77,439
    
    $
    36,642
    
    $
    (15,898
    )
    $
    26,556
    
    $
    121,897Total
      Assets
    
    $
    2,833,906
    
    $
    2,855,398
    
    $
    2,861,614
    
    $
    2,875,908
    
    $
    3,010,657**CAPITALIZATION
      AS OF DECEMBER 31:**Common
      Stockholder’s Equity
    
    $
    835,327
    
    $
    749,521
    
    $
    681,195
    
    $
    629,805
    
    $
    610,847Preferred
      Stock Not Subject to Mandatory
      Redemption
    
    
    126,000
    
    
    126,000
    
    
    126,000
    
    
    126,000
    
    
    210,000Long-Term
      Debt
    
    
    300,299
    
    
    270,072
    
    
    557,265
    
    
    646,174
    
    
    944,193Total
      Capitalization
    
    $
    1,261,626
    
    $
    1,145,593
    
    $
    1,364,460
    
    $
    1,401,979
    
    $
    1,765,040**CAPITALIZATION
      RATIOS AS OF DECEMBER 31:**Common
      Stockholder’s Equity
    
    
    66.2
    %
    
    65.4
    %
    
    49.9
    %
    
    44.6
    %
    
    34.6
    %Preferred
      Stock Not Subject to Mandatory
      Redemption
    
    
    10.0
    
    
    11.0
    
    
    9.2
    
    
    9.0
    
    
    11.9Long-Term
      Debt
    
    
    23.8
    
    
    23.6
    
    
    40.9
    
    
    46.4
    
    
    53.5Total
      Capitalization
    
    
    100.0
    %
    
    100.0
    %
    
    100.0
    %
    
    100.0
    %
    
    100.0
    %**DISTRIBUTION
      KWH DELIVERIES (Millions)**Residential
    
    
    2,316
    
    
    2,312
    
    
    2,427
    
    
    2,258
    
    
    2,183Commercial
    
    
    2,796
    
    
    2,771
    
    
    2,702
    
    
    2,667
    
    
    2,380Industrial
    
    
    5,006
    
    
    5,097
    
    
    5,280
    
    
    5,397
    
    
    5,595Other
    
    
    56
    
    
    69
    
    
    57
    
    
    61
    
    
    49Total
    
    
    10,174
    
    
    10,249
    
    
    10,466
    
    
    10,383
    
    
    10,207**CUSTOMERS
      SERVED:**Residential
    
    
    273,800
    
    
    270,258
    
    
    272,474
    
    
    270,589
    
    
    269,071Commercial
    
    
    36,710
    
    
    36,969
    
    
    32,037
    
    
    31,680
    
    
    31,413Industrial
    
    
    211
    
    
    215
    
    
    1,883
    
    
    1,898
    
    
    1,917Other
    
    
    504
    
    
    451
    
    
    468
    
    
    443
    
    
    598Total
    
    
    311,225
    
    
    307,893
    
    
    306,862
    
    
    304,610
    
    
    302,999**Number
      of Employees**
    
    
    **414**
    
    
    **446**
    
    
    **508**
    
    
    **507**
    
    
    **539**
 
 
  3
  **THE TOLEDO
EDISON COMPANY**
 
 **MANAGEMENT’S
DISCUSSION AND**
 **ANALYSIS OF
RESULTS OF OPERATIONS**
 **AND
FINANCIAL CONDITION**
 
 
 *This discussion
includes forward-looking statements based on information currently available to
management. Such statements are subject to certain risks and uncertainties.
These statements typically contain, but are not limited to, the terms
"anticipate," "potential," "expect," "believe," "estimate" and similar words.
Actual results may differ materially due to the speed and nature of increased
competition and deregulation in the electric utility industry, economic or
weather conditions affecting future sales and margins, changes in markets for
energy services, changing energy and commodity market prices, replacement power
costs being higher than anticipated or inadequately hedged, maintenance costs
being higher than anticipated, legislative and regulatory changes (including
revised environmental requirements), adverse regulatory or legal decisions and
outcomes (including revocation of necessary licenses or operating permits, fines
or other enforcement actions and remedies) of governmental investigations and
oversight, including by the Securities and Exchange Commission, the United
States Attorney's Office and the Nuclear Regulatory Commission as disclosed in
our Securities and Exchange Commission filings, generally, and with respect to
the Davis-Besse Nuclear Power Station outage in particular, the availability and
cost of capital, the continuing availability and operation of generating units,
our 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 final outcome in the
proceeding related to our Application for a Rate Stabilization Plan in Ohio, the
risks and other factors discussed from time to time in our Securities and
Exchange Commission filings, and other similar factors. We expressly disclaim
any current intention to update any forward-looking statements contained herein
as a result of new information, future events, or otherwise.*
 
 **Results
of Operations**
 
 Earnings on common
stock increased to $77 million in 2004 from $37 million in 2003. Earnings on
common stock in 2003 included an after-tax gain of $26 million from the
cumulative effect of an accounting change due to the adoption of SFAS 143.
Income before the cumulative effect increased to $86 million from $20 million in
2003. This increase resulted primarily from the restart of the Davis-Besse
Nuclear Power Station in April 2004 that contributed to higher operating
revenues and lower nuclear operating costs; interest charges were also lower in
2004. These factors were partially offset by higher fuel and purchased power
costs, other operating costs and depreciation and amortization
costs.
 Earnings on common
stock increased to $37 million in 2003 from a loss of $16 million in 2002.
Income before the cumulative effect of an accounting change was $20 million in
2003, compared to a loss of $5 million in 2002. The increase in 2003 reflected
lower fuel and purchased power costs, other operating costs, depreciation and
financing costs and net proceeds of $12 million (pre-tax) from the settlement of
our claim against NRG Energy, Inc. (see Note 7), partially offset by lower
operating revenues, higher nuclear operating costs and amortization of
regulatory assets.
 
 Operating revenues
increased by $76 million or 8.1% in 2004 from 2003. The increase in revenues
resulted principally from a $98 million (69.0%) increase in wholesale sales
(primarily to FES) due to increased nuclear generation available for sale,
partially offset by a $6 million decrease in retail generation sales revenues
from franchise customers and $5 million of shopping incentive credits discussed
below. Reduced retail generation revenues (residential and commercial - $4
million and $5 million, respectively) in 2004 reflected increases in electric
generation services to residential and commercial customers provided by
alternative suppliers as a percent of total sales deliveries in TE’s franchise
area of 6.9 percentage points and 2.5 percentage points, respectively, while
shopping by industrial customers decreased slightly. Increased industrial
customer generation revenue of $3 million was due to higher unit prices
offsetting a 1.5% decrease in KWH sales.
 
 Revenues from
distribution throughput decreased by $7 million in 2004 compared to 2003,
primarily as a result of lower unit prices in all customer sectors. Distribution
deliveries to the aggregate industrial and commercial sector decreased and
deliveries to residential customers were nearly unchanged in 2004 as compared to
2003.
  4
  
 Operating revenues
decreased by $64 million or 6.4% in 2003 from 2002. Reduced revenues resulted
from lower KWH sales due to milder weather in the second and third quarters,
continued sluggishness in the regional economy and increased sales by
alternative suppliers. KWH sales to retail customers in all customer sectors
(residential, commercial and industrial) declined by 9.0% in 2003 from 2002,
reducing generation retail sales revenues by $49.8 million. Electric generation
services provided to retail customers by alternative suppliers as a percent of
total sales delivered in our service area increased 5.9 percentage points in
2003. Sales revenues from wholesale customers decreased by $19 million in 2003
compared to 2002. KWH sales to the wholesale market declined in 2003 due to
reduced nuclear generation available for sale to FES. Available generation
decreased due to the extended outage at Davis-Besse and additional nuclear
refueling activities in 2003 compared to 2002. Distribution deliveries decreased
2.1% in 2003 from 2002. However, higher unit prices resulted in overall revenue
increases from electricity throughput of $17.2 million when compared to 2002.
 
 Under the Ohio
transition plan, we provide incentives to customers to encourage switching to
alternative energy providers - $5 million of additional credits in 2004,
compared with 2003; and $7 million of additional credits in 2003, compared to
2002. These revenue
reductions are deferred for future recovery under our transition plan and do not
affect current period earnings.
 
 Changes in electric
generation sales and distribution deliveries for 2004 and 2003, from the prior
year are summarized in the following table:
 
 **Changes
      in KWH Sales**
    
    **2004**
    
    **2003****Increase
      (Decrease)**Electric
      Generation:Retail
    
    
    (3.8
    )%
    
    (9.0
    )%Wholesale
    
    
    69.0
    %
    
    (15.4
    )%**Total
      Electric Generation Sales**
    
    
    **26.2**
    **%**
    
    **(11.8**
    **)%**Distribution
      Deliveries:Residential
    
    
    0.2
    %
    
    (4.8
    )%Commercial
      and industrial
    
    
    (0.8
    )%
    
    (1.4
    )%**Total
      Distribution Deliveries**
    
    
    **(0.7**
    **)%**
    
    **(2.1**
    **)%**
 
 
 *Operating
Expenses and Taxes*
 
 Total operating
expenses and taxes increased by $18 million in 2004 and decreased by $63 million
in 2003. 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
    
    $
    18
    
    $
    (6
    )Purchased
      power costs
    
    
    12
    
    
    (27
    )Nuclear
      operating costs
    
    
    (87
    )
    
    2Other
      operating costs
    
    
    27
    
    
    (16
    )Provision for
      depreciation
    
    
    4
    
    
    (28
    )Amortization
      of regulatory assets
    
    
    10
    
    
    9Deferral of
      new regulatory assets
    
    
    (11
    )
    
    (3
    )General
      taxes
    
    
    3
    
    
    (2
    )Income
      taxes
    
    
    42
    
    
    8**Total
      operating expenses and taxes**
    
    **$**
    **18**
    
    **$**
    **(63**
    **)**
 
 
 Higher fuel costs
in 2004, compared with 2003, resulted principally from increased nuclear
generation, which was up 109.4%. Purchased power costs increased in 2004,
compared with 2003, due to higher unit costs partially offset by lower KWH
purchased due to lower retail generation sales requirements. Decreased nuclear
operating costs in 2004 were due to reduced incremental costs associated with
the extended Davis-Besse outage, unplanned work performed during the Perry
Plant's 56-day nuclear refueling outage in 2003 and the 28-day refueling outage
at Beaver Valley Unit 2 in 2003. Other operating costs increased in 2004,
compared to 2003, reflecting higher employee benefits costs - specifically an
increase in health care costs.
  5
  
 Lower fuel and
purchased power costs in 2003, compared with 2002, resulted from reduced nuclear
generation - down 19.9%, and reduced KWH required for customer needs which more
than offset an increase in unit costs. Increased nuclear costs resulted from
incremental costs associated with the extended Davis-Besse outage, the Perry
Plant's nuclear refueling outage and the refueling outage at Beaver Valley Unit
2 in 2003, compared with a 24-day refueling outage at Beaver Valley Unit 2, in
the first quarter of 2002. A decrease in other operating costs in 2003 reflect
lower employee costs - specifically the absence of short-term incentive
compensation and reduced health care costs.
 
 Depreciation
charges increased by $4 million in 2004 compared to 2003 due to a higher level
of depreciable property in 2004. Charges for depreciation decreased by $28
million in 2003, compared with 2002, primarily due to revised service life
assumptions for nuclear generating plants and lower charges resulting from the
implementation of SFAS 143 ($15 million). The increase in charges for
amortization of regulatory assets in 2004 and 2003, compared to the prior years,
reflected increases in transition costs amortization. The higher deferrals of
new regulatory assets in 2004 and 2003 compared to the prior year were due to
higher shopping incentives ($5 million) and deferred interest on the shopping
incentives ($6 million) in 2004 and higher shopping incentive deferrals ($7
million) partially offset by lower tax related deferrals ($4 million) in
2003.
 
 General taxes
increased $3 million in 2004 primarily due to the absence of settled property
tax claims in 2003 and correspondingly decreased $2 million in 2003 due to
settled property tax claims.
 
 *Other
Income*
 
 Other Income
increased by $2 million in 2004, compared to 2003, due to $16 million of
interest income from Shippingport Capital Trust (see Note 6 - Variable Interest
Entities) beginning in 2004 partially offset by the absence of the $12 million
NRG settlement in 2003. Other income increased in 2003 from 2002 reflecting the
2003 NRG settlement.
 
 *Net Interest
Charges*
 
 Net interest
charges continued to trend lower, decreasing by $7 million in 2004 and $19
million in 2003, compared to the prior year, reflecting redemptions and
refinancing since 2003. We redeemed $230 million of long-term debt and repriced
$121 million of pollution control notes during 2004.
 
 *Cumulative
Effect of Accounting Change*
 
 Upon adoption of
SFAS 143 in the first quarter of 2003, we recorded an after-tax gain to net
income of $26 million. The cumulative effect adjustment for unrecognized
depreciation and accretion, offset by the reduction in the existing
decommissioning liabilities and ceasing the accounting practice of depreciating
non-regulated generation assets using a cost of removal component, was a $44
million increase to income, or $26 million net of income taxes.
 
 **Capital
Resources and Liquidity**
 
 Our cash
requirements in 2004 for operating expenses, construction expenditures and
scheduled debt maturities were met without increasing our net debt and preferred
stock outstanding. 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 $15,000 of cash and cash equivalents, compared
with $2 million as of December 31, 2003. The major sources for changes in
these balances are summarized below.
  6
  
 *Cash Flows From
Operating Activities*
 
 Net cash provided
from operating activities was $183 million in 2004, $61 million in 2003 and $166
million in 2002, summarized as follows:
 
 **Operating
      Cash Flows**
    
    **2004**
    
    **2003**
    
    **2002*****(In
      millions)***Cash earnings(1)
    
    $
    240
    
    $
    119
    
    $
    61Pension trust
      contribution(2)
    
    
    (8
    )
    
    --
    
    
    --Working
      capital and other
    
    
    (49
    )
    
    (58
    )
    
    105Total
    
    $
    183
    
    $
    61
    
    $
    166
 
 (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)
    
    $
    86
    
    $
    45
    
    $
    (5
    )Non-Cash
      Charges (Credits):Provision for
      depreciation
    
    
    58
    
    
    55
    
    
    82Amortization
      of regulatory assets
    
    
    124
    
    
    114
    
    
    105Nuclear fuel
      and capital lease amortization
    
    
    25
    
    
    9
    
    
    12Deferral of
      new regulatory assets
    
    
    (39
    )
    
    (28
    )
    
    (25
    )Deferred
      operating lease costs, net
    
    
    (23
    )
    
    (37
    )
    
    (25
    )Accrued
      retirement benefits obligation
    
    
    6
    
    
    6
    
    
    (59
    )Accrued
      compensation
    
    
    1
    
    
    (5
    )
    
    3Deferred
      income taxes and investment tax credits, net
    
    
    2
    
    
    4
    
    
    (27
    )Cumulative
      effect of accounting change
    
    
    --
    
    
    (44
    )
    
    --Cash earnings
      (Non-GAAP)
    
    $
    240
    
    $
    119
    
    $
    61
 
 
 Net cash provided
from operating activities increased $122 million in 2004 from 2003 as a result
of a $121 million increase in cash earnings as described above under "Results of
Operations" and a $9 million increase from changes in working capital. These
increases were partially offset by a $8 million after-tax voluntary pension
trust contribution.
 
 Net cash provided
from operating activities decreased $105 million in 2003 from 2002 as a result
of a $163 million decrease in working capital partially offset by a $58 million
increase in cash earnings as described under "Results of Operations". The
largest factor contributing to the change in working capital was a $95 million
comparative change in accounts payable.
 
 *Cash Flows From
Financing Activities*
 
 Net cash used for
financing activities increased by $101 million in 2004 from 2003 and decreased
by $36 million in 2003 from 2002.
  7
  
 The following table
provides details regarding new issues and redemptions during 2004, 2003 and
2002:
 
 
 **Securities
      Issued or Redeemed**
    
    **2004**
    
    **2003**
    
    **2002*****(In
      millions)***New
      IssuesPollution
      Control Notes
    
    $
    104
    
    $
    --
    
    $
    20RedemptionsUnsecured
      Notes
    
    $
    --
    
    $
    7
    
    $
    135Secured
      Notes
    
    
    261
    
    
    183
    
    
    44Preferred
      Stock
    
    
    --
    
    
    --
    
    
    85Other,
      principally redemption premiums
    
    
    1
    
    
    1
    
    
    2$
    262
    
    $
    191
    
    $
    266Short-term
      Borrowings, Net
    
    $
    74
    
    $
    206
    
    $
    132
 
 
 As of
December 31, 2004, we had $136 million of cash and temporary investments
(which include short-term notes receivable from associated companies) and $430
million of short-term indebtedness. We obtained authorization from the PUCO to
incur short-term debt of up to $500 million (including the utility money pool
described below). We had the capability to issue $998 million of additional FMB
on the basis of property additions and retired bonds under the terms of our
mortgage indenture. Based upon applicable earnings coverage tests, we could
issue up to $736 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. Companies receiving
a loan under the money pool agreements must repay the principal, together with
accrued interest, within 364 days of borrowing the funds. The rate of interest
is the same for each company receiving a loan from the pool and is based on the
average cost of funds available through the pool. The average interest rate for
borrowings in 2004 was 1.43%.
 
 Our access to
capital markets and costs of financing are dependent on the ratings of our
securities and the securities of FirstEnergy. The following table shows
securities ratings as of December 31, 2004. The ratings outlook on all
securities is stable.
 
 
 **Ratings
      of Securities****Securities**
    **S&P**
    **Moody’s**
    **Fitch****FirstEnergy**
    Senior
      unsecured
    BB+
    Baa3
    BBB-**TE**
    Senior
      secured
    BBB-
    Baa2
    BBB-Senior
      unsecured
    BB+
    Baa3
    BBPreferred
      stock
    BB
    Ba2
    BB-
 
 
 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 for
investing activities increased to $91 million in 2004 from $86 million in 2003.
This increase was primarily due to the change in the investment in lessor notes,
partially offset by lower property additions.
  8
  
 Our capital
spending for the period 2005-2007 is expected to be about $192 million
(excluding nuclear fuel), of which approximately $56 million applies to 2005.
Investments for additional nuclear fuel during the 2005-2007 period are
estimated to be approximately $54 million, of which about $8 million applies to
2005. During the same period, our nuclear fuel investments are expected to be
reduced by approximately $64 million and $20 million, respectively, as the
nuclear fuel is consumed .
 
 **Contractual
Obligations**
 
 As of December 31,
2004, our estimated cash payments under existing contractual obligations that we
consider firm obligations were as follows:
 
 
 **2006-**
    
    **2008-****Contractual
      Obligations**
    
    **Total**
    
    **2005**
    
    **2007**
    
    **2009**
    
    **Thereafter*****(In
      millions)***Long-term
      debt (3)
    
    $
    383
    
    $
    --
    
    $
    30
    
    $
    --
    
    $
    353Short-term
      borrowings
    
    
    430
    
    
    430
    
    
    --
    
    
    --
    
    
    --Operating
      leases(1)
    
    
    918
    
    
    79
    
    
    158
    
    
    145
    
    
    536Purchases
      (2)
    
    
    264
    
    
    38
    
    
    96
    
    
    81
    
    
    49Total
    
    $
    1,995
    
    $
    547
    
    $
    284
    
    $
    226
    
    $
    938
 
 (1)  Operating
lease payments are net of capital trust receipts of $302.2 million (see Note
5).
 (2) Fuel and power purchases under contracts with fixed or minimum
quantities and approximate timing.
 (3) 
Amounts reflected to not include interest on long-term
debt.
 
 **Off-Balance
Sheet Arrangements**
 
 Obligations not
included on our Consolidated Balance Sheet primarily consist of sale and
leaseback arrangements involving the Bruce Mansfield Plant and Beaver Valley
Unit 2, which are reflected in the operating lease payments above (see Note 5 -
Leases). As of December 31, 2004, the present value of these operating
lease commitments, net of trust investments, total $570 million.
 
 We sell
substantially all of our retail customer receivables to CFC, a wholly owned
subsidiary of CEI. CFC subsequently transfers the receivables to a trust (a
"qualified special purpose entity" under SFAS 140) under an asset-backed
securitization agreement. This arrangement provided $29 million of off-balance
sheet financing as of December 31, 2004.
 
 **Interest
Rate Risk**
 
 Our exposure to
fluctuations in market interest rates is reduced since a significant portion of
our debt has fixed interest rates. The table below presents principal amounts
and related weighted average interest rates by year of maturity for our
investment portfolio and debt obligations.
 **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
    
    $
    134
    
    $
    12
    
    $
    9
    
    $
    15
    
    $
    12
    
    $
    289
    
    **$**
    **471**
    
    **$**
    **515**Average
      interest rate
    
    
    7.8
    %
    
    7.7
    %
    
    7.7
    %
    
    7.7
    %
    
    7.7
    %
    
    6.6
    %
    
    7.1
    %LiabilitiesLong-term
      Debt and OtherLong-Term
      Obligations:Fixed
      rate
    
    
    
    
    
    
    
    $
    30
    
    
    
    
    
    
    
    $
    113
    
    **$**
    **143**
    
    **$**
    **150**Average
      interest rate
    
    
    
    
    
    
    
    
    7.1
    
    
    
    
    
    
    
    
    7.5
    %
    
    7.4
    %Variable
      rate
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    240
    
    **$**
    **240**
    
    **$**
    **240**Average
      interest rate
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2.2
    %
    
    2.2
    %Short-term
      Borrowings
    
    $
    430
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    **$**
    **430**
    
    **$**
    **430**Average
      interest rate
    
    
    2.0
    %
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2.0
    %
 
  9
  
 **Equity
Price Risk**
 
 Included in our
nuclear decommissioning trust investments are marketable equity securities
carried at their market value of approximately $188 million and $145 million as
of December 31, 2004 and 2003, respectively. A hypothetical 10% decrease in
prices quoted by stock exchanges would result in a $19 million reduction in fair
value as of December 31, 2004 (see Note 4 - Fair Value of Financial
Instruments).
 
 **Outlook**
 
 Our industry
continues to transition to a more competitive environment and all of our
customers can select alternative energy suppliers. We continue to deliver power
to residential homes and businesses through our existing distribution system,
which remains regulated. Customer rates have been restructured into separate
components to support customer choice. 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.
 
 *Regulatory
Matters*
 
 In 2001, Ohio
customer rates were restructured to establish separate charges for transmission,
distribution, transition cost recovery and a generation-related component. When
one of our customers elects to obtain power from an alternative supplier, we
reduce the customer's bill with a "generation shopping credit," based on the
regulated generation component (plus an incentive), and the customer receives a
generation charge from the alternative supplier. We have continuing PLR
responsibility to our franchise customers through December 31, 2005.
 
 Regulatory assets
are costs which have been authorized by the PUCO and the FERC for recovery from
customers in future periods or for which authorization is probable. Without the
probability of such authorization, costs currently recorded as regulatory assets
would have been charged to income as incurred. Our regulatory assets as of
December 31, 2004 and 2003 were $375 million and $459 million,
respectively. All of our regulatory assets are expected to continue to be
recovered under the provisions of the transition and rate stabilization
plans.
 
 As part of the Ohio
transition plan we are obligated to supply electricity to customers who do not
choose an alternative supplier. We are also required to provide 160 MW of low
cost supply to unaffiliated alternative suppliers who serve customers within our
service area. Our competitive retail sales affiliate, FES, acts as an alternate
supplier for a portion of the load in our franchise area.
 
 On
February 24, 2004, we filed a revised Rate Stabilization Plan to address
PUCO concerns related to the original Rate Stabilization Plan. On June 9,
2004, the PUCO issued an order approving the revised Rate Stabilization Plan,
subject to conducting a competitive bid process. On August 5, 2004, we
accepted the Rate Stabilization Plan as modified and approved by the PUCO on
August 4, 2004. In the second quarter of 2004, we implemented the
accounting modifications related to the extended amortization periods and
interest cost deferrals on the deferred customer shopping incentive balances. On
October 1 and October 4, 2004, the OCC and NOAC, respectively, filed
appeals with the Supreme Court of Ohio to overturn the June 9, 2004 PUCO
order and associated entries on rehearing.
 
 The revised Rate
Stabilization Plan extends current generation prices through 2008, ensuring
adequate generation supply at stabilized prices, and continues our support of
energy efficiency and economic development efforts. Other key components of the
revised Rate Stabilization Plan include the following:
 
 ·
    extension of
      the amortization period for transition costs being recovered through the
      RTC from mid-2007 to as late as mid-2008;·
    deferral of
      interest costs on the accumulated customer shopping incentives as new
      regulatory assets; and·
    ability to
      request increases in generation charges during 2006 through 2008, under
      certain limited conditions, for increases in fuel costs and
      taxes.
 
 On December 9,
2004, the PUCO rejected the auction price results from a required competitive
bid process and issued an entry stating that the pricing under the approved
revised Rate Stabilization Plan will take effect on January 1, 2006. The
PUCO may cause us to undertake, no more often than annually, a similar
competitive bid process to secure generation for the years 2007 and 2008. Any
acceptance of future competitive bid results would terminate the Rate
Stabilization Plan pricing, but not the related approved accounting, and not
until twelve months after the PUCO authorizes such termination.
  10
  On
December 30, 2004, we filed an application with the PUCO seeking tariff
adjustments to recover increases of approximately $0.1 million in transmission
and ancillary service costs beginning January 1, 2006. We also filed an
application for authority to defer costs associated with MISO Day 1, MISO Day 2,
congestion fees, FERC assessment fees, and the ATSI rate increase, as
applicable, from October 1, 2003 through December 31, 2005. Various
parties have intervened in these cases.
 
 See Note 8 to the
consolidated financial statements for a more complete and detailed discussion of
regulatory matters in Ohio.
 
 *Environmental
Matters*
 
 We believe we are
in compliance with current SO 2 and NO x reduction
requirements under the Clean Air Act Amendments of 1990. In 1998, the EPA
finalized regulations requiring additional NO x reductions from
our Ohio and Pennsylvania facilities. Various regulatory and judicial actions
have since sought to further define NO x reduction
requirements (see Note 12(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 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" 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.
  11
  
 *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.
 
 We have been named
as a PRP at waste disposal sites, which may require cleanup under the
Comprehensive Environmental Response, Compensation and Liability Act of 1980.
Allegations of disposal of hazardous substances at historical sites and the
liability involved are often unsubstantiated and subject to dispute; however,
federal law provides that all PRPs for a particular site are liable on a joint
and several basis. Therefore, environmental liabilities that are considered
probable have been recognized on the Consolidated Balance Sheet as of
December 31, 2004, based on estimates of the total costs of cleanup, our
proportionate responsibility for such costs and the financial ability of other
nonaffiliated entities to pay. Included in Current Liabilities and Other
Noncurrent Liabilities are accrued liabilities aggregating approximately $0.2
million as of December 31, 2004. We accrue environmental liabilities only
when we can conclude that it is probable that we have an obligation for such
costs and can reasonably determine the amount of such costs. Unasserted claims
are reflected in our determination of environmental liabilities and are accrued
in the period that they are both probable and reasonably estimable.
 
 *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 KWH of electricity
we generate 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 our plants. In addition, Ohio and
Pennsylvania have water quality standards applicable to our 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 their 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.
 
 *Other Legal
Proceedings*
 
 *Power Outages
and Related Litigation-*
 
 Three substantially
similar actions were filed in various Ohio state courts by plaintiffs seeking to
represent customers who allegedly suffered damages as a result of the
August 14, 2003 power outages. All three cases were dismissed for lack of
jurisdiction. One case was refiled at the PUCO. The other two cases were
appealed. One case was dismissed and no further appeal was sought. The remaining
case is pending. In addition to the one case that was refiled at the PUCO, the
Ohio Companies were named as respondents in a regulatory proceeding that was
initiated at the PUCO in response to complaints alleging failure to provide
reasonable and adequate service stemming primarily from the August 14, 2003
power outages.
  12
  
 One complaint has
been filed against FirstEnergy in the New York State Supreme Court. In this
case, several plaintiffs in the New York City metropolitan area allege that they
suffered damages as a result of the August 14, 2003 power outages. None of
the plaintiffs are customers of any FirstEnergy affiliate. FirstEnergy filed a
motion to dismiss with the Court on October 22, 2004. No timetable for a
decision on the motion to dismiss has been established by the Court. No damage
estimate has been provided and thus potential liability has not been
determined.
 
 FirstEnergy is
vigorously defending these actions, but cannot predict the outcome of any of
these proceedings or whether any further regulatory proceedings or legal actions
may be initiated against the Companies. In particular, if FirstEnergy or its
subsidiaries were ultimately determined to have legal liability in connection
with these proceedings, it could have a material adverse effect on our financial
condition and results of operations.
 
 *Nuclear Plant
Matters-*
 
 In late 2003, FENOC
received a subpoena from a grand jury in the United States District Court for
the Northern District of Ohio, Eastern Division, requesting the production of
certain documents and records relating to the inspection and maintenance of the
reactor vessel head at the Davis-Besse Nuclear Power Station. FirstEnergy is
unable to predict the outcome of this investigation. On December 10, 2004,
FirstEnergy received a letter from the United States Attorney's Office stating
that FENOC is a target of the federal grand jury investigation into alleged
false statements relating to the Davis-Besse Nuclear Power Station outage made
to the NRC in the Fall of 2001 in response to NRC Bulletin 2001-01. The letter
also said that the designation of FENOC as a target indicates that, in the view
of the prosecutors assigned to the matter, it is likely that federal charges
will be returned against FENOC by the grand jury. On February 10, 2005, FENOC
received an additional subpoena for documents related to root cause reports
regarding reactor head degradation and the assessment of reactor head management
issues at Davis-Besse. In addition, FENOC remains subject to possible civil
enforcement action by the NRC in connection with the events leading to the
Davis-Besse outage in 2002.
 On August 12, 2004,
the NRC notified FENOC that it will increase its regulatory oversight of the
Perry Nuclear Power Plant as a result of problems with safety system equipment
over the past two years. FENOC operates the Perry Nuclear Power Plant, in which
we have a 19.91% 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.
 
 *Other 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 not otherwise discussed above are described herein.
 
 On October 20,
2004, FirstEnergy was notified by the SEC that the previously disclosed informal
inquiry initiated by the SEC's Division of Enforcement in September 2003
relating to the restatements in August 2003 of previously reported results by
FirstEnergy and TE, and the Davis-Besse extended outage, have become the subject
of a formal order of investigation. The SEC's formal order of investigation also
encompasses issues raised during the SEC's examination of FirstEnergy and the
Companies under the PUHCA. Concurrent with this notification, FirstEnergy
received a subpoena asking for background documents and documents related to the
restatements and Davis-Besse issues. On December 30, 2004, FirstEnergy
received a second subpoena asking for documents relating to issues raised during
the SEC's PUHCA examination. FirstEnergy has cooperated fully with the informal
inquiry and will continue to do so with the formal investigation.
 
 If it were
ultimately determined that FirstEnergy or its subsidiaries have legal liability
or are otherwise made subject to liability based on any of the above matters, it
could have a material adverse effect on our financial condition and results of
operations.
 
 ***Critical
Accounting Policies***
 
 We prepare our
consolidated financial statements in accordance with GAAP. Application of these
principles often requires a high degree of judgment, estimates and assumptions
that affect financial results. All of our assets are subject to their own
specific risks and uncertainties and are regularly reviewed for impairment. Our
more significant accounting policies are described below.
  13
  
 *Regulatory
Accounting*
 
 We are subject to
regulation that sets the prices (rates) we are permitted to charge our customers
based on the costs that the regulatory agencies determine we are permitted to
recover. At times, regulators permit the future recovery through rates of costs
that would be currently charged to expense by an unregulated company. This
rate-making process results in the recording of regulatory assets based on
anticipated future cash inflows. We regularly review these assets to assess
their ultimate recoverability within the approved regulatory guidelines.
Impairment risk associated with these assets relates to potentially adverse
legislative, judicial or regulatory actions in the future.
 
 *Revenue
Recognition*
 
 We follow the
accrual method of accounting for revenues, recognizing revenue for electricity
that has been delivered to customers but not yet billed through the end of the
accounting period. The determination of electricity sales to individual
customers is based on meter readings, which occur on a systematic basis
throughout the month. At the end of each month, electricity delivered to
customers since the last meter reading is estimated and a corresponding accrual
for unbilled sales is recognized. The determination of unbilled sales requires
management to make estimates regarding electricity available for retail load,
transmission and distribution line losses, demand by customer class,
weather-related impacts, prices in effect for each customer class and
electricity provided by alternative suppliers.
 *Pension and
Other Postretirement Benefits Accounting*
 
 Our reported costs
of providing non-contributory defined pension benefits and postemployment
benefits other than pensions are dependent upon numerous factors resulting from
actual plan experience and certain assumptions.
 
 Pension and OPEB
costs are affected by employee demographics (including age, compensation levels,
and employment periods), the level of contributions we make to the plans, and
earnings on plan assets. Such factors may be further affected by business
combinations, which impact employee demographics, plan experience and other
factors. Pension and OPEB costs are also affected by changes to key assumptions,
including anticipated rates of return on plan assets, the discount rates and
health care trend rates used in determining the projected benefit obligations
for pension and OPEB costs.
 
 In accordance with
SFAS 87, changes in pension and OPEB obligations associated with these factors
may not be immediately recognized as costs on the income statement, but
generally are recognized in future years over the remaining average service
period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes
due to the long-term nature of pension and OPEB obligations and the varying
market conditions likely to occur over long periods of time. As such,
significant portions of pension and OPEB costs recorded in any period may not
reflect the actual level of cash benefits provided to plan participants and are
significantly influenced by assumptions about future market conditions and plan
participants' experience.
 
 In selecting an
assumed discount rate, we consider currently available rates of return on
high-quality fixed income investments expected to be available during the period
to maturity of the pension and other postretirement benefit obligations. Due to
recent declines in corporate bond yields and interest rates in general, we
reduced the assumed discount rate as of December 31, 2004 to 6.00% from
6.25% and 6.75% used as of December 31, 2003 and 2002, respectively.
 
 Our assumed rate of
return on pension plan assets considers historical market returns and economic
forecasts for the types of investments held by the pension trusts. In 2004, 2003
and 2002, plan assets actually earned 11.1%, 24.2% and (11.3)%, respectively.
Our pension costs in 2004 were computed assuming a 9.0% rate of return on plan
assets based upon projections of future returns and a pension trust investment
allocation of approximately 68% equities, 29% bonds, 2% real estate and 1% cash.
 
 In the third
quarter of 2004, FirstEnergy made a $500 million voluntary contribution to its
pension plan (our share was $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 $11 million. As
prescribed by SFAS 87, we reduced our additional minimum liability by $1
million, recording an increase in an intangible asset of $1 million and
increasing OCI by $2 million. The balance in AOCL of $8 million (net of $6
million in deferred taxes) will reverse in future periods to the extent the fair
value of trust assets exceeds the accumulated benefit obligation.
  14
  
 Health care cost
trends have significantly increased and will affect future OPEB costs. The 2004
and 2005 composite health care trend rate assumptions are approximately 10%-12%
and 9%-11%, respectively, gradually decreasing to 5% in later years. In
determining our trend rate assumptions, we included the specific provisions of
our health care plans, the demographics and utilization rates of plan
participants, actual cost increases experienced in our health care plans, and
projections of future medical trend rates.
 
 *Ohio Transition
Cost Amortization*
 
 In connection with
our initial Ohio transition plan, the PUCO determined allowable transition costs
based on amounts recorded on our regulatory books. These costs exceeded those
deferred or capitalized on our balance sheet prepared under GAAP since they
included certain costs which have not yet been incurred or that were recognized
on the regulatory financial statements (fair value purchase accounting
adjustments). We use an effective interest method for amortizing transition
costs, often referred to as a "mortgage-style" amortization. The interest rate
under this method is equal to the rate of return authorized by the PUCO in our
Rate Stabilization Plan. In computing the transition cost amortization, we
include only the portion of the transition revenues associated with transition
costs included on the balance sheet prepared under GAAP. Revenues collected for
the off balance sheet costs and the return associated with these costs are
recognized as income when received.
 *Long-Lived
Assets*
 
 In accordance with
SFAS 144, we periodically evaluate our long-lived assets to determine whether
conditions exist that would indicate that the carrying value of an asset might
not be fully recoverable. The accounting standard requires that if the sum of
future cash flows (undiscounted) expected to result from an asset is less than
the carrying value of the asset, an asset impairment must be recognized in the
financial statements. If impairment has occurred, we recognize a loss -
calculated as the difference between the carrying value and the estimated fair
value of the asset (discounted future net cash flows).
  
 The calculation of
future cash flows is based on assumptions, estimates and judgement 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.
 
 *Goodwill*
 
 In a business
combination, the excess of the purchase price over the estimated fair values of
the assets acquired and liabilities assumed is recognized as goodwill. Based on
the guidance provided by SFAS 142, we evaluate our goodwill for impairment at
least annually and would make such an evaluation more frequently if indicators
of impairment should arise. In accordance with the accounting standard, if the
fair value of a reporting unit is less than its carrying value (including
goodwill), the goodwill is tested for impairment. If impairment were indicated,
we would recognize a loss - calculated as the
difference between the implied fair value of our goodwill and the carrying value
of the goodwill. Our annual review was completed in the third quarter of 2004,
with no impairment of goodwill indicated. The forecasts used in our evaluation
of goodwill reflect operations consistent with our general business assumptions.
Unanticipated changes in those assumptions could have a significant effect on
our future evaluations of goodwill. As of December 31, 2004, we had
approximately $505 million of goodwill.
 *Nuclear
Decommissioning*
 
 In accordance with
SFAS No. 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.
  15
  
 **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.
 
   16
   **THE TOLEDO
EDISON COMPANY**
 
 **CONSOLIDATED
STATEMENTS OF INCOME**
 
 
 **For
      the Years Ended December 31,**
    
    **2004**
    
    **2003**
    
    **2002*****(In
      thousands)*****OPERATING
      REVENUES (a) (Note 2(I))**
    
    $
    1,008,112
    
    $
    932,335
    
    $
    996,045**OPERATING
      EXPENSES AND TAXES:**Fuel and
      purchased power (Note 2(I))
    
    
    363,759
    
    
    333,539
    
    
    366,932Nuclear
      operating costs
    
    
    168,401
    
    
    254,986
    
    
    252,608Other
      operating costs (Note 2(I))
    
    
    152,879
    
    
    125,869
    
    
    141,997Provision for
      depreciation
    
    
    57,948
    
    
    54,524
    
    
    82,316Amortization
      of regulatory assets
    
    
    123,858
    
    
    113,664
    
    
    104,300Deferral of
      new regulatory assets
    
    
    (38,696
    )
    
    (27,575
    )
    
    (24,534
    )General
      taxes
    
    
    54,142
    
    
    50,742
    
    
    53,223Income taxes
      (benefit)
    
    
    32,746
    
    
    (9,074
    )
    
    (17,496
    )Total
      operating expenses and taxes
    
    
    915,037
    
    
    896,675
    
    
    959,346**OPERATING
      INCOME**
    
    
    93,075
    
    
    35,660
    
    
    36,699**OTHER
      INCOME (NET OF INCOME TAXES) (Notes 2(I) and 7)**
    
    
    22,951
    
    
    20,558
    
    
    13,329**NET
      INTEREST CHARGES:**Interest on
      long-term debt
    
    
    27,153
    
    
    38,874
    
    
    58,120Allowance for
      borrowed funds used during
      construction
      and capitalized interest
    
    
    (3,696
    )
    
    (5,838
    )
    
    (2,502
    )Other
      interest expense (credit)
    
    
    6,286
    
    
    3,252
    
    
    (448
    )Net interest
      charges
    
    
    29,743
    
    
    36,288
    
    
    55,170**INCOME
      (LOSS) BEFORE CUMULATIVE EFFECT OF****ACCOUNTING
      CHANGE**
    
    
    86,283
    
    
    19,930
    
    
    (5,142
    )Cumulative
      effect of accounting change (net of income taxes
      of
      $18,201,000) (Note 2(G))
    
    
    --
    
    
    25,550
    
    
    --**NET
      INCOME (LOSS)**
    
    
    86,283
    
    
    45,480
    
    
    (5,142
    )**PREFERRED
      STOCK DIVIDEND REQUIREMENTS**
    
    
    8,844
    
    
    8,838
    
    
    10,756**EARNINGS
      (LOSS) ON COMMON STOCK**
    
    $
    77,439
    
    $
    36,642
    
    $
    (15,898
    )
 
 (a)
    Includes
      electric sales to associated companies of $305 million, $212 million and
      $232 million in 2004, 2003 and 2002,
respectively.
 
 The accompanying
Notes to Consolidated Financial Statements are an integral part of these
statements.
 
 
  17
  **THE TOLEDO
EDISON COMPANY**
 
 **CONSOLIDATED
BALANCE SHEETS**
 
 **As of
      December 31,**
    
    **2004**
    
    **2003****ASSETS**
    
    ***(In
      thousands****)***UTILITY
      PLANT:**In
      service
    
    $
    1,856,478
    
    $
    1,714,870Less-Accumulated
      provision for depreciation
    
    
    778,864
    
    
    721,7541,077,614
    
    
    993,116Construction
      work in progress-Electric
      plant
    
    
    58,535
    
    
    125,051Nuclear
      fuel
    
    
    15,998
    
    
    20,18974,533
    
    
    145,2401,152,147
    
    
    1,138,356**OTHER
      PROPERTY AND INVESTMENTS:**Investment in
      lessor notes (Note 5)
    
    
    190,692
    
    
    200,938Nuclear plant
      decommissioning trusts
    
    
    297,803
    
    
    240,634Long-term
      notes receivable from associated companies
    
    
    39,975
    
    
    163,626Other
    
    
    2,031
    
    
    2,119530,501
    
    
    607,317**CURRENT
      ASSETS:**Cash and cash
      equivalents
    
    
    15
    
    
    2,237Receivables-Customers
    
    
    4,858
    
    
    4,083Associated
      companies
    
    
    36,570
    
    
    29,158Other
    
    
    3,842
    
    
    14,386Notes
      receivable from associated companies
    
    
    135,683
    
    
    19,316Materials and
      supplies, at average cost
    
    
    40,280
    
    
    35,147Prepayments
      and other
    
    
    1,150
    
    
    6,704222,398
    
    
    111,031**DEFERRED
      CHARGES:**Regulatory
      assets
    
    
    374,814
    
    
    459,040Goodwill
    
    
    504,522
    
    
    504,522Property
      taxes
    
    
    24,100
    
    
    24,443Other
    
    
    25,424
    
    
    10,689928,860
    
    
    998,694$
    2,833,906
    
    $
    2,855,398**CAPITALIZATION
      AND LIABILITIES****CAPITALIZATION**(See
      Consolidated Statements of Capitalization):Common
      stockholder’s equity
    
    $
    835,327
    
    $
    749,521Preferred
      stock not subject to mandatory redemption
    
    
    126,000
    
    
    126,000Long-term
      debt
    
    
    300,299
    
    
    270,0721,261,626
    
    
    1,145,593**CURRENT
      LIABILITIES:**Currently
      payable long-term debt
    
    
    90,950
    
    
    283,650Short-term
      borrowings
    
    
    --
    
    
    70,000Accounts
      payable-Associated
      companies
    
    
    110,047
    
    
    132,876Other
    
    
    2,247
    
    
    2,816Notes payable
      to associated companies
    
    
    429,517
    
    
    285,953Accrued
      taxes
    
    
    46,957
    
    
    55,604Lease market
      valuation liability
    
    
    24,600
    
    
    24,600Other
    
    
    53,055
    
    
    49,711757,373
    
    
    905,210**NONCURRENT
      LIABILITIES:**Accumulated
      deferred income taxes
    
    
    221,950
    
    
    201,954Accumulated
      deferred investment tax credits
    
    
    25,102
    
    
    27,200Retirement
      benefits
    
    
    39,227
    
    
    47,006Asset
      retirement obligation
    
    
    194,315
    
    
    181,839Lease market
      valuation liability
    
    
    268,000
    
    
    292,600Other
    
    
    66,313
    
    
    53,996814,907
    
    
    804,595**COMMITMENTS
      AND CONTINGENCIES**(Notes 5 and
      12)$
    2,833,906
    
    $
    2,855,398
 
 
 The accompanying
Notes to Consolidated Financial Statements are an integral part of these balance
sheets.
 
   18
   **THE TOLEDO
EDISON COMPANY**
 
 **CONSOLIDATED
STATEMENTS OF CAPITALIZATION**
 
 **As of
      December 31,**
    
    **2004**
    
    **2003*****(Dollars in
      thousands, except per share amounts)*****COMMON
      STOCKHOLDER'S EQUITY:**Common
      stock, $5 par value, authorized 60,000,000 shares
      39,133,887
      shares outstanding
    
    $
    195,670
    
    $
    195,670Other
      paid-in capital
    
    
    428,559
    
    
    428,559Accumulated
      other comprehensive income (Note 2(F))
    
    
    20,039
    
    
    11,672Retained
      earnings (Note 9(A))
    
    
    191,059
    
    
    113,620Total
      common stockholder's equity
    
    
    835,327
    
    
    749,521
 
 **Number
      of Shares Outstanding**
    
    **Optional
      Redemption Prices****2004**
    
    **2003**
    
    **Per
      Share**
    
    **Aggregate****PREFERRED
      STOCK NOT SUBJECT TO****MANDATORY
      REDEMPTION (Note 9(B)):**Cumulative,
      $100 par value-Authorized
      3,000,000 shares$4.25
    
    
    160,000
    
    
    160,000
    
    $
    104.63
    
    $
    16,740
    
    
    16,000
    
    
    16,000$4.56
    
    
    50,000
    
    
    50,000
    
    
    101.00
    
    
    5,050
    
    
    5,000
    
    
    5,000$4.25
    
    
    100,000
    
    
    100,000
    
    
    102.00
    
    
    10,200
    
    
    10,000
    
    
    10,000310,000
    
    
    310,000
    
    
    
    
    
    31,990
    
    
    31,000
    
    
    31,000Cumulative,
      $25 par value-Authorized
      12,000,000 shares$2.365
    
    
    1,400,000
    
    
    1,400,000
    
    
    27.75
    
    
    38,850
    
    
    35,000
    
    
    35,000Adjustable
      Series A
    
    
    1,200,000
    
    
    1,200,000
    
    
    25.00
    
    
    30,000
    
    
    30,000
    
    
    30,000Adjustable
      Series B
    
    
    1,200,000
    
    
    1,200,000
    
    
    25.00
    
    
    30,000
    
    
    30,000
    
    
    30,0003,800,000
    
    
    3,800,000
    
    
    
    
    
    98,850
    
    
    95,000
    
    
    95,000Total
    
    
    4,110,000
    
    
    4,110,000
    
    
    
    
    $
    130,840
    
    
    126,000
    
    
    126,000
 
 **LONG-TERM
      DEBT (Note 9(C)):**First
      mortgage bonds:7.875%
      due 2004
    
    
    --
    
    
    145,000Total
      first mortgage bonds
    
    
    --
    
    
    145,000Unsecured
      notes:* 
      1.980% due 2030
    
    
    34,850
    
    
    34,850* 
      4.500% due 2033
    
    
    31,600
    
    
    31,600* 
      2.000% due 2033
    
    
    18,800
    
    
    18,800* 
      3.100% due 2033
    
    
    5,700
    
    
    --Total
      unsecured notes
    
    
    90,950
    
    
    85,250Secured
      notes:7.670% due 2004
    
    
    --
    
    
    70,0007.130% due 2007
    
    
    30,000
    
    
    30,0007.625% due 2020
    
    
    45,000
    
    
    45,0007.750% due 2020
    
    
    54,000
    
    
    54,0009.220% due 2021
    
    
    --
    
    
    15,0008.000% due 2023
    
    
    --
    
    
    30,500*
      1.750% due 2024
    
    
    67,300
    
    
    --6.100% due 2027
    
    
    10,100
    
    
    10,1005.375% due 2028
    
    
    3,751
    
    
    3,751*
      1.690% due 2033
    
    
    30,900
    
    
    30,900* 1.800% due 2033
    
    
    20,200
    
    
    20,200*
      1.750% due 2033
    
    
    30,500
    
    
    --Total
      secured notes
    
    
    291,751
    
    
    309,451Net
      unamortized premium on debt
    
    
    8,548
    
    
    14,021Long-term
      debt due within one year
    
    
    (90,950
    )
    
    (283,650
    )Total
      long-term debt
    
    
    300,299
    
    
    270,072**TOTAL
      CAPITALIZATION**
    
    $
    1,261,626
    
    $
    1,145,593
 
 *  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.
 
   19
   **THE TOLEDO
EDISON COMPANY**
 
 **CONSOLIDATED
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY**
 
 
 ****
    
    ****
    
    ****
    
    ****
    
    **Accumulated**
    
    ********
    
    ****
    
    ****
    
    ****
    
    **Other**
    
    **Other**
    
    ********
    
    **Comprehensive**
    
    **Number**
    
    **Par**
    
    **Paid-In**
    
    **Comprehensive**
    
    **Retained******
    
    **Income
      (Loss)**
    
    **of
      Shares**
    
    **Value**
    
    **Capital**
    
    **Income
      (Loss)**
    
    **Earnings******
    
    *(Dollars
      in thousands)*****Balance,
      January 1, 2002
    
    
    
    39,133,887
    
    $195,670
    
    $328,559
    
    $
      7,100
    
    $
      98,476Net
      loss
    
    $
    (5,142
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    (5,142
    )Unrealized
      loss on investments, net of (4,034,000) of
      income taxes
    
    
    (5,997
    )
    
    
    
    
    
    
    
    
    
    
    (5,997
    )Minimum
      liability for unfunded retirement benefits, net of
      $(15,042,000) of income taxes.
    
    
    (21,115
    )
    
    
    
    
    
    
    
    
    
    
    (21,115
    )Comprehensive
      loss
    
    $
    (32,254
    )Equity
      contribution from parent
    
    
    
    
    
    
    
    
    
    
    
    100,000Cash dividends
      on preferred stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (9,457
    )Cash dividends
      on common stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (5,600
    )Preferred
      stock redemption premiums
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (1,299
    )Balance,
      December 31, 2002
    
    
    
    
    
    39,133,887
    
    
    195,670
    
    
    428,559
    
    
    (20,012
    )
    
    76,978Net
      income
    
    $
    45,480
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    45,480Unrealized
      gain on investments, net of $13,908,000 of
      income taxes
    
    
    19,988
    
    
    
    
    
    
    
    
    
    
    
    19,988Minimum
      liability for unfunded retirement benefits, net of
      $8,489,000 of income taxes.
    
    
    11,696
    
    
    
    
    
    
    
    
    
    
    
    11,696Comprehensive
      income
    
    $
    77,164Cash dividends
      on preferred stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (8,838
    )Balance,
      December 31, 2003
    
    
    
    
    
    39,133,887
    
    
    195,670
    
    
    428,559
    
    
    11,672
    
    
    113,620Net
      income
    
    $
    86,283
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    86,283Unrealized
      gain on investments, net of $5,246,000 of
      income taxes
    
    
    7,253
    
    
    
    
    
    
    
    
    
    
    
    7,253Minimum
      liability for unfunded retirement benefits, net of
      $717,000 of income taxes.
    
    
    1,114
    
    
    
    
    
    
    
    
    
    
    
    1,114Comprehensive
      income
    
    $
    94,650Cash dividends
      on preferred stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (8,844
    )Balance,
      December 31, 2004
    
    
    
    
    
    39,133,887
    
    $
    195,670
    
    $
    428,559
    
    $
    20,039
    
    $
    191,059
 
 
 
 
 **CONSOLIDATED
STATEMENTS OF PREFERRED STOCK**
 
 **Not
      Subject to**
      **Mandatory
      Redemption****Number**
    
    **Carrying****of
      Shares**
    
    **Value*****(Dollars
      in thousands)***Balance,
      January 1, 2002
    
    
    5,700,000
    
    $
    210,000Redemptions$8.32
      Series
    
    
    (100,000
    )
    
    (10,000
    )$7.76
      Series
    
    
    (150,000
    )
    
    (15,000
    )$7.80
      Series
    
    
    (150,000
    )
    
    (15,000
    )$10.00
      Series
    
    
    (190,000
    )
    
    (19,000
    )$2.21
      Series
    
    
    (1,000,000
    )
    
    (25,000
    )Balance,
      December 31, 2002
    
    
    4,110,000
    
    
    126,000Balance,
      December 31, 2003
    
    
    4,110,000
    
    
    126,000Balance,
      December 31, 2004
    
    
    4,110,000
    
    $
    126,000
 
 
 The accompanying
Notes to Consolidated Financial Statements are an integral part of these
statements.
  20
  **THE TOLEDO
EDISON COMPANY**
 
 **CONSOLIDATED
STATEMENTS OF CASH FLOWS**
 **For
      the Years Ended December 31,**
    
    **2004**
    
    **2003**
    
    **2002*****(In
      thousands)*****CASH
      FLOWS FROM OPERATING ACTIVITIES:**Net Income
      (Loss)
    
    $
    86,283
    
    $
    45,480
    
    $
    (5,142
    )Adjustments
      to reconcile net income (loss) to net
      cash from
      operating activities:Provision for
      depreciation
    
    
    57,948
    
    
    54,524
    
    
    82,316Amortization
      of regulatory assets
    
    
    123,858
    
    
    113,664
    
    
    104,300Deferral of
      new regulatory assets
    
    
    (38,696
    )
    
    (27,575
    )
    
    (24,534
    )Nuclear fuel
      and capital lease amortization
    
    
    25,034
    
    
    9,289
    
    
    11,866Deferred
      rents and lease market valuation liability
    
    
    (23,121
    )
    
    (37,001
    )
    
    (24,600
    )Deferred
      income taxes and investment tax credits, net
    
    
    6,123
    
    
    3,563
    
    
    (26,672
    )Accrued
      retirement benefit obligation
    
    
    5,889
    
    
    6,205
    
    
    (59,123
    )Accrued
      compensation, net
    
    
    1,074
    
    
    (5,365
    )
    
    2,614Cumulative
      effect of accounting change (Note 2(G))
    
    
    --
    
    
    (43,751
    )
    
    --Pension trust
      contribution
    
    
    (12,572
    )
    
    --
    
    
    --Decrease
      (increase) in operating assets:Receivables
    
    
    10,228
    
    
    19,107
    
    
    5,164Materials and
      supplies
    
    
    (5,133
    )
    
    1,481
    
    
    (5,582
    )Prepayments
      and other current assets
    
    
    5,554
    
    
    (3,249
    )
    
    11,125Increase
      (decrease) in operating liabilities:Accounts
      payable
    
    
    (23,398
    )
    
    (53,765
    )
    
    40,801Accrued
      taxes
    
    
    (8,647
    )
    
    20,928
    
    
    (4,881
    )Accrued
      interest
    
    
    (9,080
    )
    
    (3,965
    )
    
    (3,541
    )Other
    
    
    (18,438
    )
    
    (38,977
    )
    
    61,538Net cash
      provided from operating activities
    
    
    182,906
    
    
    60,593
    
    
    165,649**CASH
      FLOWS FROM FINANCING ACTIVITIES:**New
      Financing-Long-term
      debt
    
    
    103,500
    
    
    --
    
    
    19,580Short-term
      borrowings, net
    
    
    73,565
    
    
    206,300
    
    
    132,445Equity
      contributions from parent
    
    
    --
    
    
    --
    
    
    100,000Redemptions
      and Repayments-Preferred
      stock
    
    
    --
    
    
    --
    
    
    (85,299
    )Long-term
      debt
    
    
    (262,162
    )
    
    (190,794
    )
    
    (180,368
    )Dividend
      Payments-Common
      stock
    
    
    --
    
    
    --
    
    
    (5,600
    )Preferred
      stock
    
    
    (8,844
    )
    
    (8,844
    )
    
    (10,057
    )Net cash
      provided from (used for) financing activities
    
    
    (93,941
    )
    
    6,662
    
    
    (29,299
    )**CASH
      FLOWS FROM INVESTING ACTIVITIES:**Property
      additions
    
    
    (64,629
    )
    
    (84,924
    )
    
    (105,510
    )Loan
      repayments from (payments to) associated companies, net
    
    
    7,284
    
    
    (18,826
    )
    
    5,838Investment in
      lessor notes (Note 5)
    
    
    10,246
    
    
    40,025
    
    
    21,168Contributions
      to nuclear decommissioning trust
    
    
    (28,541
    )
    
    (28,541
    )
    
    (28,541
    )Other
    
    
    (15,547
    )
    
    6,560
    
    
    (8,919
    )Net cash used
      for investing activities
    
    
    (91,187
    )
    
    (85,706
    )
    
    (115,964
    )Net increase
      (decrease) in cash and cash equivalents
    
    
    (2,222
    )
    
    (18,451
    )
    
    20,386Cash and cash
      equivalents at beginning of period
    
    
    2,237
    
    
    20,688
    
    
    302Cash and cash
      equivalents at end of period
    
    $
    15
    
    $
    2,237
    
    $
    20,688**SUPPLEMENTAL
      CASH FLOWS INFORMATION:**Cash Paid
      During the Year-Interest (net
      of amounts capitalized)
    
    $
    40,082
    
    $
    38,576
    
    $
    61,498Income taxes
      (refund)
    
    $
    53,728
    
    $
    (9,257
    )
    $
    3,561
 
 The accompanying
Notes to Consolidated Financial Statements are an integral part of these
statements.
 
  21
  **THE TOLEDO
EDISON COMPANY**
 
 **CONSOLIDATED
STATEMENTS OF TAXES**
 
 
 
 **For
      the Years Ended December 31,**
    
    **2004**
    
    **2003**
    
    **2002*****(In
      thousands)*****GENERAL
      TAXES:**Ohio
      kilowatt-hour excise*
    
    $
    28,158
    
    $
    29,793
    
    $
    28,046Real and
      personal property
    
    
    23,559
    
    
    18,488
    
    
    22,737Social
      security and unemployment
    
    
    2,089
    
    
    1,861
    
    
    1,684Other
    
    
    336
    
    
    600
    
    
    756Total general
      taxes
    
    $
    54,142
    
    $
    50,742
    
    $
    53,223**PROVISION
      FOR INCOME TAXES:**Currently
      payable-Federal
    
    $
    34,587
    
    $
    15,495
    
    $
    12,845State
    
    
    11,640
    
    
    4,537
    
    
    3,98346,227
    
    
    20,032
    
    
    16,828Deferred,
      net-Federal
    
    
    7,156
    
    
    4,414
    
    
    (19,091
    )State
    
    
    1,064
    
    
    1,205
    
    
    (5,570
    )8,220
    
    
    5,619
    
    
    (24,661
    )Investment
      tax credit amortization
    
    
    (2,097
    )
    
    (2,056
    )
    
    (2,011
    )Total
      provision for (benefit from) income taxes
    
    $
    52,350
    
    $
    23,595
    
    $
    (9,844
    )**INCOME
      STATEMENT CLASSIFICATION****OF
      PROVISION FOR INCOME TAXES:**Operating
      income
    
    $
    32,746
    
    $
    (9,074
    )
    $
    (17,496
    )Other
      income
    
    
    19,604
    
    
    14,468
    
    
    7,652Cumulative
      effect of accounting change
    
    
    --
    
    
    18,201
    
    
    --Total
      provision for (benefit from) income taxes
    
    $
    52,350
    
    $
    23,595
    
    $
    (9,844
    )**RECONCILIATION
      OF FEDERAL INCOME TAX****EXPENSE
      AT STATUTORY RATE TO TOTAL****PROVISION
      FOR INCOME TAXES:**Book income
      before provision for income taxes
    
    $
    138,633
    
    $
    69,075
    
    $
    (14,986
    )Federal
      income tax expense at statutory rate
    
    $
    48,522
    
    $
    24,176
    
    $
    (5,245
    )Increases
      (reductions) in taxes resulting from-State income
      taxes, net of federal income tax benefit
    
    
    8,258
    
    
    3,732
    
    
    (1,031
    )Amortization
      of investment tax credits
    
    
    (2,097
    )
    
    (2,056
    )
    
    (2,011
    )Amortization
      of tax regulatory assets
    
    
    (2,492
    )
    
    (2,397
    )
    
    (2,362
    )Other,
      net
    
    
    159
    
    
    140
    
    
    805Total
      provision for (benefit from) income taxes
    
    $
    52,350
    
    $
    23,595
    
    $
    (9,844
    )**ACCUMULATED
      DEFERRED INCOME TAXES****AS OF
      DECEMBER 31:**Property
      basis differences
    
    $
    216,933
    
    $
    193,409
    
    $
    177,262Regulatory
      transition charge
    
    
    101,190
    
    
    151,129
    
    
    196,812Unamortized
      investment tax credits
    
    
    (9,606
    )
    
    (10,472
    )
    
    (11,414
    )Deferred gain
      for asset sale to affiliated company
    
    
    11,111
    
    
    12,618
    
    
    14,186Other
      comprehensive income
    
    
    14,084
    
    
    8,121
    
    
    (14,276
    )Above market
      leases
    
    
    (120,078
    )
    
    (130,231
    )
    
    (140,399
    )Retirement
      benefits
    
    
    41
    
    
    (4,568
    )
    
    (9,768
    )Shopping
      credit incentive deferral
    
    
    36,628
    
    
    21,416
    
    
    10,273All
      Other
    
    
    (28,353
    )
    
    (39,468
    )
    
    (64,397
    )Net deferred
      income tax liability
    
    $
    221,950
    
    $
    201,954
    
    $
    158,279
 
 
 *  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.
  22
  **NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS**
 
 **1.**
    **ORGANIZATION
      AND BASIS OF PRESENTATION:**
 
 The consolidated
financial statements include TE (Company) and its 90% owned subsidiary, TECC.
TECC was formed in 1997 to make equity investments in a business trust in
connection with financing related to the Bruce Mansfield Plant sale and
leaseback transaction (see Note 5). CEI, an affiliate, has a 10% interest in
TECC. The Company is a wholly owned subsidiary of FirstEnergy. FirstEnergy also
holds directly all of the issued and outstanding common shares of its other
principal electric utility operating subsidiaries, including CEI, OE, ATSI,
JCP&L, Met-Ed and Penelec.
 
 The Company follows
GAAP and complies with the regulations, orders, policies and practices
prescribed by the SEC, PUCO and FERC. The preparation of financial statements in
conformity with GAAP requires management to make periodic estimates and
assumptions that affect the reported amounts of assets, liabilities, revenues
and expenses and the disclosure of contingent assets and liabilities. Actual
results could differ from these estimates. Certain 2003 revenues and expenses
have been reclassified and presented on a net basis to conform to 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-*
 
 The Company
recognizes, as regulatory assets, costs which the FERC and the PUCO 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 will continue to be recovered from customers
under the Company's transition plan. Based on that plan, the Company continues
to bill and collect cost-based rates for its transmission and distribution
services, which remain regulated; accordingly, it is appropriate that the
Company continues the application of SFAS 71 to those operations.
 
 Net regulatory
assets on the Consolidated Balance Sheets are comprised of the
following:
 
 **2004**
    
    **2003*****(In
      millions)***Regulatory
      transition costs
    
    $
    327
    
    $
    447Customer
      shopping incentives
    
    
    89
    
    
    52Liabilities
      to customers - income taxes
    
    
    (10
    )
    
    (13
    )Loss on
      reacquired debt
    
    
    3
    
    
    3Employee
      postretirement benefit costs
    
    
    7
    
    
    8Asset removal
      costs and all other
    
    
    (41
    )
    
    (38
    )Total
    
    $
    375
    
    $
    459
 
  23
  
 The Company is
deferring customer shopping incentives and interest costs as new regulatory
assets in accordance with the transition and rate stabilization plans. These
regulatory assets, totaling $89 million as of December 31, 2004, will be
recovered through a surcharge rate equal to the RTC rate in effect when the
transition costs have been fully recovered. Recovery of the new regulatory
assets will begin at that time and amortization of the regulatory assets for
each accounting period will be equal to the surcharge revenue recognized during
that period. The company expects to recover these deferred customer shopping
incentives before the end of 2008.
 
 *Transition Cost
Amortization-*
 
 The Company
amortizes transition costs (see Regulatory Matters) using the effective interest
method. Under the current Rate Stabilization Plan, total transition cost
amortization is expected to approximate the following for 2005 through 2007:
 
 
 ***(In
      millions)***2005
    
    $
    1392006
    
    
    852007
    
    
    95
 
 
 *Accounting for
Generation Operations-*
 
 The application of
SFAS 71 was discontinued in 2000 with respect to the Company's generation
operations. The SEC's interpretive guidance and EITF 97-4 regarding asset
impairment measurement providing 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 $53 million of
impaired plant investments were recognized by the Company as regulatory assets
recoverable as transition costs through future regulatory cash flows. Net assets
included in utility plant relating to the operations for which the application
of SFAS 71 was discontinued, were $652 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. Cash and cash equivalents as of December
31, 2003 included $2 million which was included in the NRG settlement claim sold
in January 2004 (see Note 7).
 
 **(C)**
    **REVENUES
      AND RECEIVABLES-**
 
 The Company's
principal business is providing electric service to customers in Ohio. 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 $5 million (billed - $4 million and unbilled - $1
million) and $4 million (billed - $2 million and unbilled - $2 million) as of
December 31, 2004 and 2003, respectively.
  24
  
 The Company and CEI
sell substantially all of their retail customer receivables to CFC, a wholly
owned subsidiary of CEI. CFC subsequently transfers the receivables to a trust
under an asset-backed securitization agreement. The trust is a "qualified
special purpose entity" under SFAS 140, which provides it with certain rights
relative to the transferred assets. Transfers are made in return for an interest
in the trust (62% as of December 31, 2004), which is stated at fair value,
reflecting adjustments for anticipated credit losses. The fair value of CFC's
interest in the trust approximates the stated value of its retained interest in
the underlying receivables, after adjusting for anticipated credit losses,
because the average collection period is 27 days. Accordingly, subsequent
measurements of the retained interest under SFAS 115, (as an available-for-sale
financial instrument) result in no material change in value. Sensitivity
analyses reflecting 10% and 20% increases in the rate of anticipated credit
losses would not have significantly affected FirstEnergy's retained interest in
the pool of receivables through the trust.
 
 Collections of
receivables previously transferred to the trust and used for the purchase of new
receivables from CFC during 2004 totaled approximately $2.5 billion. CEI and TE
processed receivables for the trust and received servicing fees of approximately
$4.8 million ($1.6 million - the Company and $3.2 million - CEI) in 2004.
Expenses associated with the factoring discount related to the sale of
receivables were $3.5 million in 2004.
 
 **(D)**
    **UTILITY
      PLANT AND DEPRECIATION-**
 
 Utility plant
reflects original cost of construction (except for the Company's 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 annualized
composite rate was approximately 2.8% in 2004 and 2003 and 3.8% in 2002.
 
 *Jointly - Owned
Generating Stations* **-**
 
 The Company,
together with CEI, OE and Penn, own and/or lease, 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 Consolidated Statements of Income. The amounts reflected on the
Consolidated Balance Sheet under utility plant as of December 31, 2004
include the following:
 
 
 **Utility**
      **Plant**
      **in
      Service**
    
    **Accumulated**
      **Provision
      for**
      **Depreciation**
    
    **Construction**
      **Work
      in**
      **Progress**
    
    **Ownership/**
      **Leasehold**
      **Interest****Generating
      Units*****(In
      millions)***Bruce
      Mansfield Units 2 and 3
    
    $
    85
    
    $
    22
    
    $
    5
    
    
    18.61
    %Beaver Valley
      Unit 2
    
    
    15
    
    
    1
    
    
    10
    
    
    19.91
    %Davis-Besse
    
    
    305
    
    
    66
    
    
    31
    
    
    48.62
    %Perry
    
    
    357
    
    
    74
    
    
    5
    
    
    19.91
    %Total
    
    $
    762
    
    $
    163
    
    $
    51
 
 
 The Bruce Mansfield
Plant and Beaver Valley Unit 2 are leased through sale and leaseback
transactions (see Note 5) and the above-related amounts represent
construction expenditures subsequent to the transaction.
 
 *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.
  25
  
 **(E)**
    **ASSET
      IMPAIRMENTS-**
 
 *Long-lived
Assets*
 
 The Company
evaluates the carrying value of its long-lived assets when events or
circumstances indicate that the carrying amount may not be recoverable. In
accordance with SFAS 144, the carrying amount of a long-lived asset is not
recoverable if it exceeds the sum of the undiscounted cash flows expected to
result from the use and eventual disposition of the asset. If an impairment
exists, a loss is recognized for the amount by which the carrying value of the
long-lived asset exceeds its estimated fair value. Fair value is estimated by
using available market valuations or the long-lived asset's expected future net
discounted cash flows. The calculation of expected cash flows is based on
estimates and assumptions about future events.
 *Goodwill*
 
 In a business
combination, the excess of the purchase price over the estimated fair values of
assets acquired and liabilities assumed is recognized as goodwill. Based on the
guidance provided by SFAS 142, the Company evaluates its goodwill for impairment
at least annually and would make such an evaluation more frequently if
indicators of impairment should arise. In accordance with the accounting
standard, if the fair value of a reporting unit is less than its carrying value
(including goodwill), the goodwill is tested for impairment. If an impairment is
indicated, the Company recognizes a loss - calculated as the difference between
the implied fair value of a reporting unit's goodwill and the carrying value of
the goodwill. The company's 2004 annual review was completed in the third
quarter of 2004 with no impairment indicated. The forecasts used
in the Company's evaluation of goodwill reflect operations consistent with its
general business assumptions. Unanticipated changes in those assumptions could
have a significant effect on its future evaluations of goodwill. As of
December 31, 2004, the Company had approximately $505 million of goodwill.
The impairment analysis includes a significant source of cash representing the
Company's recovery of transition costs as described above under "Regulatory
Matters." The Company estimates that completion of transition cost recovery will
not result in an impairment of goodwill.
 *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
investmen ts are disclosed in
Note 4.
 **(F)**
    **COMPREHENSIVE
      INCOME-**
 
 Comprehensive
income includes net income as reported on the Consolidated Statements of Income
and all other changes in common stockholder's equity except those resulting from
transactions with FirstEnergy and preferred stockholders. As of
December 31, 2004, accumulated other comprehensive income consisted of a
minimum liability for unfunded retirement benefits of $8 million and unrealized
gains on investments in securities available for sale of $28 million. As of
December 31, 2003, accumulated other comprehensive income consisted of a minimum
liability for unfunded retirement benefits of $9 million and unrealized gains on
investments in securities available for sale of $21 million.
 
 **(G)**
    **CUMULATIVE
      EFFECT OF ACCOUNTING CHANGE-**
 
 Results for 2003
include an after-tax credit to net income of $25.6 million recorded by the
Company upon adoption of SFAS 143 in January 2003. The Company identified
applicable legal obligations as defined under the new accounting 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 $41.1 million were recorded as part of the carrying
amount of the related long-lived asset, offset by accumulated depreciation of
$5.5 million. The asset retirement obligation liability at the date of adoption
was $172 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 $179.6 million.
The cumulative effect adjustment for unrecognized depreciation and accretion,
offset by the reduction in the existing decommissioning liabilities and the
reversal of accumulated estimated removal costs for non-regulated generation
assets, was a $43.8 million increase to income, or $25.6 million net of income
taxes.
  26
  
 **(H)**
    **INCOME
      TAXES-**
 
 Details of the
total provision for income taxes are shown on the Consolidated Statements of
Taxes. The Company records income taxes in accordance with the liability method
of accounting. Deferred income taxes reflect the net tax effect of temporary
differences between the carrying amounts of assets and liabilities for financial
reporting purposes and the amounts used for tax purposes. Investment tax
credits, which were deferred when utilized, are being amortized over the
recovery period of the related property. Deferred income tax liabilities related
to tax and accounting basis differences and tax credit carryforward items are
recognized at the statutory income tax rates in effect when the liabilities are
expected to be paid. Deferred tax assets are recognized based on income tax
rates expected to be in effect when they are settled. The Company is included in
FirstEnergy’s consolidated federal income tax return. The consolidated tax
liability is allocated on a "stand-alone" company basis, with the Company
recognizing any tax losses or credits it contributed to the consolidated
return.
 
 **(I)**
    **TRANSACTIONS
      WITH AFFILIATED COMPANIES-**
 
 Operating revenues,
operating expenses and other income include transactions with affiliated
companies, primarily ATSI, FES and FESC. The Ohio transition plan, as discussed
in the "Regulatory Matters" section, resulted in the corporate separation of
FirstEnergy's regulated and unregulated operations in 2001. FES operates the
generation businesses of the Company, CEI, OE and Penn. As a result, the Company
entered into power supply agreements (PSA) whereby FES purchases all of the
Company's nuclear generation and the generation from leased fossil generating
facilities 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. CFC serves as the transferor in connection with the
accounts receivable securitization for the Company and CEI. The primary
affiliated companies transactions are as follows:
 
 
 **2004**
    
    **2003**
    
    **2002*****(In
      millions)*****Operating
      Revenues:**PSA revenues
      from FES
    
    $
    204
    
    $
    103
    
    $
    128Generating
      units rent from FES
    
    
    15
    
    
    15
    
    
    14Electric
      sales to CEI
    
    
    101
    
    
    109
    
    
    104Ground lease
      with ATSI
    
    
    2
    
    
    2
    
    
    2**Operating
      Expenses:**Purchased
      power under PSA
    
    
    311
    
    
    298
    
    
    319Transmission
      expenses
    
    
    --
    
    
    19
    
    
    23FESC support
      services
    
    
    36
    
    
    35
    
    
    26**Other
      Income:**Interest
      income from ATSI
    
    
    3
    
    
    3
    
    
    3Interest
      income from FES
    
    
    10
    
    
    10
    
    
    10Interest
      income from Shippingport (Note 6)
    
    
    16
    
    
    --
    
    
    --
 
 
 FirstEnergy does
not bill directly or allocate any of its costs to any subsidiary company. Costs
are allocated to the Company from FESC, a subsidiary of FirstEnergy and a
"mutual service company" as defined in Rule 93 of the PUHCA. The majority of
costs are directly billed or assigned at no more than cost as determined by
PUHCA Rule 91. The remaining costs are for services that are provided on behalf
of more than one company, or costs that cannot be precisely identified and are
allocated using formulas that are filed annually with the SEC on Form U-13-60.
The current allocation or assignment formulas used and their bases include
multiple factor formulas; each company's proportionate amount of FirstEnergy's
aggregate direct payroll, number of employees, asset balances, revenues, number
of customers, other factors and specific departmental charge ratios. Management
believes that these allocation methods are reasonable. Intercompany transactions
with FirstEnergy and its other subsidiaries are generally settled under
commercial terms within thirty days, except for $55 million payable to
affiliates for OPEB obligations.
 
 The Company is
selling 150 megawatts of its Beaver Valley Unit 2 leased capacity entitlement to
CEI. Operating revenues for this transaction were $101 million, $109 million and
$104 million in 2004, 2003 and 2002, respectively. This sale is expected to
continue through the end of the lease period. (See Note 5.)
  27
  **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.
 
  28
  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
    
    $
    17
    
    $
    7
    
    $
    (36
    )
    $
    (33
    )Increase
      (decrease) in minimum liability
      included in
      other comprehensive income
      (net of
      tax)
    
    $
    (4
    )
    $
    (145
    )
    $
    --
    
    $
    --
 
 **Assumptions
      Used to Determine****Benefit
      Obligations As of December 31**Discount
      rate
    
    
    6.00
    %
    
    6.25
    %
    
    6.00
    %
    
    6.25
    %Rate of
      compensation increase
    
    
    3.50
    %
    
    3.50
    %**Allocation
      of Plan Assets****As of
      December 31**Asset
      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
 
  29
  
 **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
    
    $
    3
    
    $
    5
    
    $
    1
    
    $
    7
    
    $
    6
    
    $
    4
   **Weighted-Average
      Assumptions Used****to
      Determine Net Periodic Benefit Cost****for
      Years Ended December 31****Pension
      Benefits**
    
    **Other
      Benefits****2004**
    
    **2003**
    
    **2002**
    
    **2004**
    
    **2003**
    
    **2002**Discount
      rate
    
    
    6.25
    %
    
    6.75
    %
    
    7.25
    %
    
    6.25
    %
    
    6.75
    %
    
    7.25
    %Expected
      long-term return on plan assets
    
    
    9.00
    %
    
    9.00
    %
    
    10.25
    %
    
    9.00
    %
    
    9.00
    %
    
    10.25
    %Rate of
      compensation increase
    
    
    3.50
    %
    
    3.50
    %
    
    4.00
    %
 In selecting an
assumed discount rate, FirstEnergy considers currently available rates of return
on high-quality fixed income investments expected to be available during the
period to maturity of the pension and other postretirement benefit obligations.
The assumed rate of return on pension plan assets considers historical market
returns and economic forecasts for the types of investments held by the
Company's pension trusts. The long-term rate of return is developed considering
the portfolio’s asset allocation strategy.
 
 FirstEnergy employs
a total return investment approach whereby a mix of equities and fixed income
investments are used to maximize the long-term return of plan assets for a
prudent level of risk. Risk tolerance is established through careful
consideration of plan liabilities, plan funded status, and corporate financial
condition. The investment portfolio contains a diversified blend of equity and
fixed-income investments. Furthermore, equity investments are diversified across
U.S. and non-U.S. stocks, as well as growth, value, and small and large
capitalizations. Other assets such as real estate are used to enhance long-term
returns while improving portfolio diversification. Derivatives may be used to
gain market exposure in an efficient and timely manner; however, derivatives are
not used to leverage the portfolio beyond the market value of the underlying
investments. Investment risk is measured and monitored on a continuing basis
through periodic investment portfolio reviews, annual liability measurements,
and periodic asset/liability studies.
 
 
 **Assumed
      Health Care Cost Trend Rates****As of
      December 31**
    
    **2004**
    
    **2003**Health care
      cost trend rate assumed for next
      year
      (pre/post-Medicare)
    
    
    9%-11
    %
    
    10%-12
    %Rate to which
      the cost trend rate is assumed to
      decline (the
      ultimate trend rate)
    
    
    5
    %
    
    5
    %Year that the
      rate reaches the ultimate trend
      rate
      (pre/post-Medicare)
    
    
    2009-2011
    
    
    2009-2011
 
 Assumed health care
cost trend rates have a significant effect on the amounts reported for the
health care plans. A one-percentage-point change in assumed health care cost
trend rates would have the following effects:
 
 **1-Percentage-**
    
    **1-Percentage-****Point
      Increase**
    
    **Point
      Decrease*****(In
      millions)***Effect on
      total of service and interest cost
    
    $
    19
    
    $
    (16
    )Effect on
      postretirement benefit obligation
    
    $
    205
    
    $
    (179
    )
 
 
 Pursuant to FSP
106-1 issued January 12, 2004, FirstEnergy began accounting for the effects
of the Medicare Act effective January 1, 2004 because of a plan amendment
during the quarter, which required remeasurement of the plan's obligations. The
plan amendment, which increases cost-sharing by employees and retirees effective
January 1, 2005, reduced the Company’s postretirement benefit costs by $3
million during 2004.
  30
  
 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 $3 million during 2004.
 
 As a result of its
voluntary contribution and the increased market value of pension plan assets,
the Company reduced its accrued benefit cost as of December 31, 2004 by $11
million. As prescribed by SFAS 87, the company reduced its additional minimum
liability by $1 million, recording an increase in an intangible asset of $1
million and crediting OCI by $2 million. The balance in AOCL of $8 million (net
of $6 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
-*
 
 All borrowings with
initial maturities of less than one year are defined as financial instruments
under GAAP and are reported on the Consolidated Balance Sheets at cost, which
approximates their fair market value. The following table provides the
approximate fair value and related carrying amounts of long-term debt as of
December 31:
 
 **2004**
    
    **2003****Carrying**
    
    **Fair**
    
    **Carrying**
    
    **Fair****Value**
    
    **Value**
    
    **Value**
    
    **Value*****(In
      millions)***Long-term
      debt
    
    $
    383
    
    $
    390
    
    $
    540
    
    $
    564
 
 The fair value of
long-term debt reflects 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 a
corporation 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
    
    $
    78
    
    $
    78
    
    $
    65
    
    $
    65-Corporate
      debt securities
    
    
    393
    
    
    437
    
    
    400
    
    
    443471
    
    
    515
    
    
    465
    
    
    508Equity
      securities(1)
    
    
    190
    
    
    190
    
    
    148
    
    
    148$
    661
    
    $
    705
    
    $
    613
    
    $
    656
 
 (1)  Includes nuclear
decommissioning trust investments.
  31
 
 
 The fair value of
investments other than cash and cash equivalents represent cost (which
approximates fair value) or the present value of the cash inflows based on the
yield to maturity. The yields assumed were based on financial instruments with
similar characteristics and terms.
 
 Investments other
than cash and cash equivalents include held-to-maturity securities and
available-for-sale securities. Decommissioning trust investments are classified
as available-for-sale securities. The Company has no securities held for trading
purposes. The following table summarizes the amortized cost basis, gross
unrealized gains and losses and fair values for decommissioning trust
investments as of December 31:
 
 
 **2004**
    
    **2003****Cost**
    
    **Unrealized**
    
    **Unrealized**
    
    **Fair**
    
    **Cost**
    
    **Unrealized**
    
    **Unrealized**
    
    **Fair****Basis**
    
    **Gains**
    
    **Losses**
    
    **Value**
    
    **Basis**
    
    **Gains**
    
    **Losses**
    
    **Value*****(In
      millions)***Debt
      securities
    
    $
    106
    
    $
    5
    
    $
    1
    
    $
    110
    
    $
    91
    
    $
    5
    
    $
    --
    
    $
    96Equity
      securities
    
    
    143
    
    
    47
    
    
    2
    
    
    188
    
    
    114
    
    
    40
    
    
    9
    
    
    145$
    249
    
    $
    52
    
    $
    3
    
    $
    298
    
    $
    205
    
    $
    45
    
    $
    9
    
    $
    241
 
 
 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
    
    $
    269
    
    $
    147
    
    $
    144Gross
      realized gains
    
    
    22
    
    
    10
    
    
    11Gross
      realized losses
    
    
    13
    
    
    10
    
    
    16Interest and
      dividend income
    
    
    9
    
    
    7
    
    
    6
 
 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
    
    $
    40
    
    $
    1
    
    $
    1
    
    $
    --
    
    $
    41
    
    $
    1Equity
      securities
    
    
    29
    
    
    1
    
    
    5
    
    
    1
    
    
    34
    
    
    2$
    69
    
    $
    2
    
    $
    6
    
    $
    1
    
    $
    75
    
    $
    3
 
 
 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. Unrealized gains and losses applicable to the Company's
decommissioning trusts are recognized in OCI in accordance with SFAS 115, as
fluctuations in the fair value of these trust balances will eventually affect
earnings. Net unrealized gains and losses are recorded as regulatory liabilities
or assets since the differences 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.
  32
  
 **5.**
    **LEASES:**
 
 The Company leases
certain generating facilities, office space and other property and equipment
under cancelable and noncancelable leases.
 
 The Company and CEI
sold their ownership interests in Bruce Mansfield Units 1, 2 and 3 and the
Company sold a portion of its ownership interest in Beaver Valley Unit 2. In
connection with these sales, which were completed in 1987, the Company and CEI
entered into operating leases for lease terms of approximately 30 years as
co-lessees. During the terms of the leases, the Company and CEI continue to be
responsible, to the extent of their combined ownership and leasehold interest,
for costs associated with the units including construction expenditures,
operation and maintenance expenses, insurance, nuclear fuel, property taxes and
decommissioning. The Company and CEI have the right, at the end of the
respective basic lease terms, to renew the leases. The Company and CEI also have
the right to purchase the facilities at the expiration of the basic lease term
or any renewal term at a price equal to the fair market value of the
facilities.
 
 As co-lessee with
CEI, the Company is also obligated for CEI's lease payments. If CEI is unable to
make its payments under the Bruce Mansfield Plant lease, the Company would be
obligated to make such payments. No such payments have been made on behalf of
CEI. (CEI's future minimum lease payments as of December 31, 2004 were
approximately $0.2 billion, net of trust cash receipts.)
 
 Consistent with the
regulatory treatment, the rentals for capital and operating leases are charged
to operating expenses on the Consolidated Statements of Income. Such costs for
the three years ended December 31, 2004 are summarized as
follows:
 
 **2004**
    
    **2003**
    
    **2002*****(In
      millions)***Operating
      leasesInterest
      element
    
    $
    46.2
    
    $
    49.4
    
    $
    52.6Other
    
    
    51.8
    
    
    62.4
    
    
    58.6Capital
      leasesInterest
      element
    
    
    --
    
    
    --
    
    
    --Other
    
    
    --
    
    
    --
    
    
    0.3Total
      rentals
    
    $
    98.0
    
    $
    111.8
    
    $
    111.5
 
 The future minimum
lease payments as of December 31, 2004 are:
 
 **Operating
      Leases****Lease**
    
    **Capital****Payments**
    
    **Trust**
    
    **Net*****(In
      millions)***2005
    
    $
    104.8
    
    $
    25.3
    
    $
    79.52006
    
    
    107.8
    
    
    26.1
    
    
    81.72007
    
    
    99.2
    
    
    22.6
    
    
    76.62008
    
    
    96.9
    
    
    27.2
    
    
    69.72009
    
    
    98.1
    
    
    23.3
    
    
    74.8Years
      thereafter
    
    
    713.7
    
    
    177.7
    
    
    536.0Total minimum
      lease payments
    
    $
    1,220.5
    
    $
    302.2
    
    $
    918.3
 
 The Company has
recorded above-market lease liabilities for Beaver Valley Unit 2 and the Bruce
Mansfield Plant associated with the 1997 merger creating FirstEnergy. The total
above-market lease obligation of $111 million associated with Beaver Valley Unit
2 is being amortized on a straight-line basis through the end of the lease term
in 2017 (approximately $6 million per year). The total above-market lease
obligation of $298 million associated with the Bruce Mansfield Plant is being
amortized on a straight-line basis through the end of 2016 (approximately $19
million per year). As of December 31, 2004 the above-market lease
liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant totaled
approximately $292 million, of which $25 million is payable within one
year.
  33
  The Company and CEI refinanced high-cost fixed
obligations related to their 1987 sale and leaseback transaction for the Bruce
Mansfield Plant through a lower cost transaction in June and July 1997. In a
June 1997 offering (Offering), the two companies pledged $720 million aggregate
principal amount ($145 million for the Company and $575 million for CEI) of FMB
due through 2007 to a trust as security for the issuance of a like principal
amount of secured notes due through 2007. The obligations of the two companies
under these secured notes are joint and several. Using available cash,
short-term borrowings and the net proceeds from the Offering, the two companies
invested $906.5 million ($337.1 million for the Company and $569.4 million for
CEI) in a business trust, in June 1997. The trust used these funds in July 1997
to purchase lease notes and redeem all $873.2 million aggregate principal amount
of 10-1/4% and 11-1/8% secured lease obligations bonds (SLOBs) due 2003 and
2016. The SLOBs were issued by a special-purpose funding corporation in 1988 on
behalf of lessors in the two companies' 1987 sale and leaseback transactions.
The Shippingport arrangement effectively reduces lease costs related to that
transaction (see Note 6 for FIN 46R discussion).
 
 **6.**
    **VARIABLE
      INTEREST ENTITIES:**
 
 FIN 46R addresses
the consolidation of VIEs, including special-purpose entities, that are not
controlled through voting interests or in which the equity investors do not bear
the residual economic risks and rewards. FirstEnergy adopted FIN 46R for
special-purpose entities as of December 31, 2003 and for all other entities in
the first quarter of 2004. The first step under FIN 46R is to determine whether
an entity is within the scope of FIN 46R, which occurs if it is deemed to be a
VIE. The Companyconsolidates VIEs
when it is determined to be the primary beneficiary as defined by FIN 46R.

Shippingport was
established to purchase all of the SLOBs issued in connection with the Company's
and CEI's Bruce Mansfield Plant sale and leaseback transaction in 1987. The
Company and CEI used debt and available funds to purchase the notes issued by
Shippingport. Adoption of FIN 46R resulted in the consolidation of Shippingport
by CEI as of December 31, 2003.
 
 Through its
investment in Shippingport, the Company has a variable interest in certain owner
trusts that acquired the interests in the Bruce Mansfield Plant. The Company
concluded that it was not the primary beneficiary of the owner trusts and it was
therefore not required to consolidate these entities. The leases are accounted
for as operating leases in accordance with GAAP.
 
 The Company is
exposed to losses under the applicable sale-leaseback agreements upon the
occurrence of certain contingent events that the Company considers unlikely to
occur. The Company has a maximum exposure to loss under these provisions of
approximately $1 billion, which represents the net amount of casualty value
payments upon the occurrence of specified casualty events that render the
applicable plant worthless. Under the sale and leaseback agreements, the Company
has net minimum discounted lease payments of $570 million, that would not be
payable if the casualty value payments are made.
 
 **7.**
    **SALE
      OF GENERATING ASSETS:**
 
 In August 2002,
FirstEnergy cancelled a November 2001 agreement to sell four coal-fired power
plants (2,535 MW) to NRG Energy Inc. because NRG stated that it could not
complete the transaction under the original terms of the agreement. NRG filed
voluntary bankruptcy petitions in May 2003; subsequently, FirstEnergy reached an
agreement for settlement of its claim against NRG. FirstEnergy sold its entire
claim (including $32 million of cash proceeds received in December 2003) for
$170 million (Company's share - $12 million) in January 2004.
  34
  **8.**
    **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 October 2003,
the Company filed an application for a Rate Stabilization Plan with the PUCO to
establish generation service rates beginning January 1, 2006, in response
to PUCO concerns about price and supply uncertainty following the end of the
Company's transition plan market development period. On February 24, 2004,
the Company filed a revised Rate Stabilization Plan to address PUCO concerns
related to the original Rate Stabilization Plan. On June 9, 2004, the PUCO
issued an order approving the revised Rate Stabilization Plan, subject to
conducting a competitive bid process. On August 5, 2004, the Company
accepted the Rate Stabilization Plan as modified and approved by the PUCO on
August 4, 2004. In the second quarter of 2004, the Company implemented the
accounting modifications related to the extended amortization periods and
interest costs deferral on the deferred customer shopping incentive balances. On
October 1 and October 4, 2004, the OCC and NOAC, respectively, filed
appeals with the Supreme Court of Ohio to overturn the June 9, 2004 PUCO
order and associated entries on rehearing.
 
 The revised Rate
Stabilization Plan extends current generation prices through 2008, ensuring
adequate generation supply at stabilized prices, and continues the Company's
support of energy efficiency and economic development efforts. Other key
components of the revised Rate Stabilization Plan include the
following:
 
 ·
    extension of
      the amortization period for transition costs being recovered through the
      RTC from mid-2007 to as late as mid-2008;·
    deferral of
      interest costs on the accumulated customer shopping incentives as new
      regulatory assets; and·
    ability to
      request increases in generation charges during 2006 through 2008, under
      certain limited conditions, for increases in fuel costs and
      taxes.
 
 On December 9,
2004, the PUCO rejected the auction price results from a required competitive
bid process and issued an entry stating that the pricing under the approved
revised Rate Stabilization Plan will take effect on January 1, 2006. The
PUCO may cause the Company to undertake, no more often than annually, a similar
competitive bid process to secure generation for the years 2007 and 2008. Any
acceptance of future competitive bid results would terminate the Rate
Stabilization Plan pricing, but not the related approved accounting, and not
until twelve months after the PUCO authorizes such termination.
  35
 
 On
December 30, 2004, the Company filed an application with the PUCO seeking
tariff adjustments to recover increases of approximately $0.1 million in
transmission and ancillary service costs beginning January 1, 2006. The
Company also filed an application for authority to defer costs associated with
MISO Day 1, MISO Day 2, congestion fees, FERC assessment fees, and the ATSI rate
increase, as applicable, from October 1, 2003 through December 31,
2005. Various parties have intervened in these cases.
 **9.**
    **CAPITALIZATION:**
 
 **(A)**
    **RETAINED
      EARNINGS-**
 
 There are no
restrictions on retained earnings for payment of cash dividends on the Company's
common stock.
 
 **(B)**
    **PREFERRED
      AND PREFERENCE STOCK-**
 
 Preferred stock may
be redeemed by the Company in whole, or in part, with 30-90 days’
notice.
 
 The preferred
dividend rates on the Company’s Series A and Series B shares fluctuate
based on prevailing interest rates and market conditions. The dividend rates for
both issues averaged 7% in 2004.
 
 The Company has
five million authorized and unissued shares of $25 par value preference
stock.
 
 **(C)**
    **LONG-TERM
      DEBT-**
 
 The Company has a
first mortgage 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 exist
cross-default provisions among financing arrangements of FirstEnergy and the
Company.
 
 Sinking fund
requirements for FMB and maturing long-term debt for the next five years
are:
 
 ***(In
      millions)***2005
    
    $
    912006
    
    
    --2007
    
    
    302008
    
    
    --2009
    
    
    --
 
 
 Included in the
table above are amounts for 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. This amount of $91
million in 2005 represents the next time debt holders may exercise this
provision.
 
 The Company's
obligations to repay certain pollution control revenue bonds are secured by
several series of first mortgage bonds. Certain pollution control revenue bonds
are entitled to the benefit of noncancelable municipal bond insurance policies
of $149 million to pay principal of, or interest on, the pollution control
revenue bonds. To the extent that drawings are made under the policies, the
Company is entitled to a credit against its obligation to repay those bonds. The
Company pays annual premiums of 0.213% to 0.300% of the amounts of the policies
to the insurers and is obligated to reimburse the insurers for any drawings
thereunder.
 
 The Company and CEI
have unsecured LOCs of approximately $216 million in connection with the sale
and leaseback of Beaver Valley Unit 2 that expire in April 2005. The Company and
CEI are jointly and severally liable for the LOCs (see Note 5).
  36
   **10.**
    **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 ARO
increases, resulting in a period expense. 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 $172 million, including accumulated accretion for the
period from the date the liability was incurred to the date of adoption.
Accretion during 2004 was $12 million, bringing the ARO liability as of
December 31, 2004 to $194 million. The ARO includes the Company's
obligation for nuclear decommissioning of the Beaver Valley Unit 2, Davis-Besse,
and Perry nuclear 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
$297.8 million.
 
 The following table
provides the effect on income as if SFAS 143 had been applied during 2002.
 
 **Effect
      of the Change in Accounting****Principle
      Applied Retroactively**
    
    **2002*****(In
      millions)***Reported net
      loss
    
    $
    (5
    )Increase
      (Decrease):Elimination
      of decommissioning expense
    
    
    29Depreciation
      of asset retirement cost
    
    
    (1
    )Accretion of
      ARO liability
    
    
    (11
    )Non-regulated
      generation cost of removal component, net
    
    
    1Income tax
      effect
    
    
    (7
    )Net earnings
      increase
    
    
    11Net income
      adjusted
    
    $
    6
 
 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
    
    $
    182
    
    $
    172Accretion
    
    
    12
    
    
    10**Ending
      balance as of December 31**
    
    **$**
    **194**
    
    **$**
    **182**
 
 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
    
    $
    161Accretion
    
    
    11**Ending
      balance as of December 31**
    
    **$**
    **172**
 
 
 **11.**
    **SHORT-TERM
      BORROWINGS:**
 
 Short-term
borrowings outstanding as of December 31, 2004, consisted of $430 million
from affiliates. The average interest rate on short-term borrowings outstanding
as of December 31, 2004 and 2003, was 2.0% and 1.8%
respectively.
  37
  
 **12.**
    **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 and
leasehold interests in Beaver Valley Unit 2, the Davis Besse 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 $89.0 million per incident but not more than $8.8 million in any
one year for each incident.
 
 The Company is also
insured as to its respective interests in Beaver Valley Unit 2, Davis-Besse 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 $332.1 million of insurance coverage for replacement power costs
for its respective interests in Beaver Valley Unit 2, Davis-Besse and Perry.
Under these policies, the Company can be assessed a maximum of approximately
$13.8 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. In accordance with the Ohio transition plan discussed in Note 8 - Regulatory
Matters, 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 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. 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 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 the
Company's 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. The Company believes its facilities are complying with the NOx budgets
established under State Implementation Plans (SIPs) through combustion controls
and post-combustion controls, including Selective Catalytic Reduction and
Selective Non-Catalytic Reduction systems, and/or using emission
allowances.
  38
 *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 the Company operates 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.
 
 *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.
 
 The Company has
been named as a PRP at waste disposal sites, which may require cleanup under the
Comprehensive Environmental Response, Compensation and Liability Act of 1980.
Allegations of disposal of hazardous substances at historical sites and the
liability involved are often unsubstantiated and subject to dispute; however,
federal law provides that all PRPs for a particular site are liable on a joint
and several basis. Therefore, environmental liabilities that are considered
probable have been recognized on the Consolidated Balance Sheet as of
December 31, 2004, based on estimates of the total costs of cleanup, the
Company's proportionate responsibility for such costs and the financial ability
of other nonaffiliated entities to pay. Included in Current Liabilities and
Other Noncurrent Liabilities are accrued liabilities aggregating approximately
$0.2 million as of December 31, 2004. The Company accrues environmental
liabilities only when it concludes that it is probable that it has an obligation
for such costs and can reasonably determine the amount of such costs. Unasserted
claims are reflected in the Company's determination of environmental liabilities
and are accrued in the period that they are both probable and reasonably
estimable.
 
 *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 CO2 emissions could require significant capital and
other expenditures. However, the CO2 emissions per KWH 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-CO2 emitting gas-fired
and nuclear generators.
  39
 *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 Company's
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. 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 their
facilities with the performance standards. The Company 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 8).
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.
 
 Three substantially
similar actions were filed in various Ohio state courts by plaintiffs seeking to
represent customers who allegedly suffered damages as a result of the
August 14, 2003 power outages. All three cases were dismissed for lack of
jurisdiction. One case was refiled at the PUCO. The other two cases were
appealed which resulted in one case's dismissal being affirmed and the other
case is pending. In addition to the one case that was refiled at the PUCO, the
Ohio Companies were named as respondents in a regulatory proceeding that was
initiated at the PUCO in response to complaints alleging failure to provide
reasonable and adequate service stemming primarily from the August 14, 2003
power outages.
 
 One complaint has
been filed against FirstEnergy in the New York State Supreme Court. In this
case, several plaintiffs in the New York City metropolitan area allege that they
suffered damages as a result of the August 14, 2003 power outages. None of
the plaintiffs are customers of any FirstEnergy affiliate. FirstEnergy filed a
motion to dismiss with the Court on October 22, 2004. No timetable for a
decision on the motion to dismiss has been established by the Court. No damage
estimate has been provided and thus potential liability has not been determined.
  40
  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.
 
 *Nuclear Plant
Matters*
 FENOC received a
subpoena in late 2003, from a grand jury in the United States District Court for
the Northern District of Ohio, Eastern Division, requesting the production of
certain documents and records relating to the inspection and maintenance of the
reactor vessel head at the Davis-Besse Nuclear Power Station. On December 10,
2004, FirstEnergy received a letter from the United States Attorney's Office
stating that FENOC is a target of the federal grand jury investigation into
alleged false statements relating to the Davis-Besse Nuclear Power Station
outage made to the NRC in the Fall of 2001 in response to NRC Bulletin 2001-01.
The letter also said that the designation of FENOC as a target indicates that,
in the view of the prosecutors assigned to the matter, it is likely that federal
charges will be returned against FENOC by the grand jury. On February 10, 2005,
FENOC received an additional subpoena for documents related to root cause
reports regarding reactor head degradation and the assessment of reactor head
management issues at Davis-Besse. In addition, FENOC remains subject to possible
civil enforcement action by the NRC in connection with the events leading to the
Davis-Besse outage in 2002.
 
 On August 12, 2004,
the NRC notified FENOC that it will increase its regulatory oversight of the
Perry Nuclear Power Plant as a result of problems with safety system equipment
over the past two years. FENOC operates the Perry Nuclear Power Plant, in which
the Company has a 19.91% 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.
 
 *Other 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
and its subsidiaries. The most significant not otherwise discussed above are
described herein.
 On October 20,
2004, FirstEnergy was notified by the SEC that the previously disclosed informal
inquiry initiated by the SEC's Division of Enforcement in September 2003
relating to the restatements in August 2003 of previously reported results by
FirstEnergy and the Company, and the Davis-Besse extended outage, have become
the subject of a formal order of investigation. The SEC's formal order of
investigation also encompasses issues raised during the SEC's examination of
FirstEnergy and the Companies under the PUHCA. Concurrent with this
notification, FirstEnergy received a subpoena asking for background documents
and documents related to the restatements and Davis-Besse issues. On
December 30, 2004, FirstEnergy received a second subpoena asking for
documents relating to issues raised during the SEC's PUHCA examination.
FirstEnergy has cooperated fully with the informal inquiry and will continue to
do so with the formal investigation.
 
 If it were
ultimately determined that FirstEnergy or its subsidiaries have legal liability
or are otherwise made subject to liability based on any of the above matters, it
could have a material adverse effect on FirstEnergy's or its subsidiaries'
financial condition and results of operations.
 
 **13.**
    **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.
  41
  
 *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 TE 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.
  42
  **14.**
    **SUMMARY
      OF QUARTERLY FINANCIAL DATA (UNAUDITED):**
 
 The following
summarizes certain consolidated operating results by quarter for 2004 and
2003.
 
 
 **March
      31,**
      **2004**
    
    **June
      30,**
      **2004**
    
    **September
      30,**
      **2004**
    
    **December
      31,**
      **2004****Three
      Months Ended*****(In
      millions)***Operating
      Revenues
    
    $
    235.4
    
    $
    243.4
    
    $
    276.3
    
    $
    253.0Operating
      Expenses and Taxes
    
    
    224.9
    
    
    216.7
    
    
    251.4
    
    
    221.9Operating
      Income
    
    
    10.5
    
    
    26.7
    
    
    24.9
    
    
    31.1Other
      Income
    
    
    5.8
    
    
    4.7
    
    
    4.2
    
    
    8.3Net Interest
      Charges
    
    
    8.8
    
    
    9.8
    
    
    4.6
    
    
    6.6Net
      Income
    
    $
    7.5
    
    $
    21.6
    
    $
    24.5
    
    $
    32.8Earnings on
      Common Stock
    
    $
    5.3
    
    $
    19.4
    
    $
    22.2
    
    $
    30.5
 
 
 **March
      31,**
    
    **June
      30,**
    
    **September
      30,**
    
    **December
      31,****Three
      Months Ended**
    
    **2003**
    
    **2003**
    
    **2003**
    
    **2003*****(In
      millions)***Operating
      Revenues
    
    $
    231.8
    
    $
    216.0
    
    $
    260.2
    
    $
    224.3Operating
      Expenses and Taxes
    
    
    226.5
    
    
    217.9
    
    
    241.4
    
    
    210.9Operating
      Income (Loss)
    
    
    5.3
    
    
    (1.9
    )
    
    18.8
    
    
    13.4Other Income
    
    
    3.1
    
    
    3.8
    
    
    5.7
    
    
    8.0Net Interest
      Charges
    
    
    9.1
    
    
    11.1
    
    
    7.9
    
    
    8.3Income (Loss)
      Before Cumulative
      Effect of
      Accounting Change
    
    
    (0.7
    )
    
    (9.2
    )
    
    16.6
    
    
    13.1Cumulative
      Effect of Accounting
      Change (Net
      of Income Taxes)
    
    
    25.6
    
    
    --
    
    
    --
    
    
    --Net Income
      (Loss)
    
    $
    24.9
    
    $
    (9.2
    )
    $
    16.6
    
    $
    13.1Earnings on
      Common Stock
    
    $
    22.7
    
    $
    (11.4
    )
    $
    14.4
    
    $
    10.9
 
 43