**OHIO EDISON
COMPANY**
 
 **2004 ANNUAL
REPORT TO STOCKHOLDERS**
 
 
 
 Ohio Edison Company
is a wholly owned electric utility operating subsidiary of FirstEnergy Corp.
Ohio Edison engages in the generation, distribution and sale of electric energy
to communities in an area of 7,500 square miles in central and northeastern Ohio
and, through its wholly owned Pennsylvania Power Company subsidiary, 1,500
square miles in western Pennsylvania. It also engages in the sale, purchase and
interchange of electric energy with other electric companies.
 
 
 
 
 
 
 
 **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
    
    
    19-20Consolidated
      Statements of Common Stockholder's Equity
    
    
    21Consolidated
      Statements of Preferred Stock
    
    
    21Consolidated
      Statements of Cash Flows
    
    
    22Consolidated
      Statements of Taxes
    
    
    23Notes to
      Consolidated Financial Statements
    
    
    24-44
 
 
 
   **GLOSSARY OF
TERMS**
 
 The following
abbreviations and acronyms are used in this report to identify Ohio Edison
Company and its affiliates:
 
 ATSI
    American
      Transmission Systems, Inc., owns and operates transmission
      facilitiesCEI
    The Cleveland
      Electric Illuminating Company, an affiliated Ohio electric
      utilityCompanies
    OE and
      PennFES
    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
      CompanyOhio
      Companies
    CEI, OE and
      TEPenelec
    Pennsylvania
      Electric Company, an affiliated Pennsylvania electric
    utilityPenn
    Pennsylvania
      Power Company, OE's wholly owned Pennsylvania electric utility
      subsidiaryPNBV
    PNBV Capital
      Trust, a special purpose entity created by OE in 1996TE
    The Toledo
      Edison Company, an affiliated Ohio electric utilityThe following
      abbreviations and acronyms are used to identify frequently used terms in
      this report:ALJ
    Administrative
      Law JudgeAOCL
    Accumulated
      Other Comprehensive LossAPB
    Accounting
      Principles BoardAPB
      29
    APB Opinion
      No. 29, "Accounting for Nonmonetary Transactions"ARB
    Accounting
      Research BulletinARB
      43
    ARB No. 43,
      "Restatement and Revision of Accounting Research
  Bulletins"ARO
    Asset
      Retirement ObligationCO2
    Carbon
      DioxideCTC
    Competitive
      Transition ChargeECAR
    East Central
      Area Reliability Coordination AgreementEITF
    Emerging
      Issues Task ForceEITF
      03-1
    EITF Issue
      No. 03-1, "The Meaning of Other-Than-Temporary and Its Application to
      Certain
      Investments”EITF
      03-16
    EITF Issue
      No. 03-16, “Accounting for Investments in Limited Liability
      Companies”EITF
      97-4
    EITF Issue
      No. 97-4, “Deregulation of the Pricing of Electricity - Issues Related to
      the Application of FASB Statements No. 71 and 101”EPA
    Environmental
      Protection AgencyFASB
    Financial
      Accounting Standards BoardFERC
    Federal
      Energy Regulatory CommissionFIN
      46R
    FASB
      Interpretation No. 46 (revised December 2003), "Consolidation of Variable
      Interest Entities"FMB
    First
      Mortgage BondsFSP EITF
      03-1-1
    FASB Staff
      Position No. EITF Issue 03-1-1, "Effective Date of Paragraphs 10-20 of
      EITF Issue
      No. 03-1,*The
      Meaning of Other-Than-Temporary Impairment and Its Application to Certain
      Investments"*FSP
      106-1
    FASB Staff
      Position No.106-1, "Accounting and Disclosure Requirements Related to the
      Medicare
      Prescription
      Drug, Improvement and Modernization Act of 2003"FSP
      106-2
    FASB Staff
      Position No.106-2, "Accounting and Disclosure Requirements Related to
      the
      Medicare
      Prescription Drug, Improvement and Modernization Act of
    2003"FSP
      109-1
    FASB Staff
      Position No. 109-1, "Application of FASB Statement No. 109, Accounting for
      Income Taxes,
      to the
      Tax Deduction and Qualified Production Activities provided by the American
      Jobs Creation Act of 2004"GAAP
    Accounting
      Principles Generally Accepted in the United StatesIRS
    Internal
      Revenue ServiceKWH
    Kilowatt-hoursLOC
    Letter of
      CreditMACT
    Maximum
      Achievable Control TechnologiesMedicare
      Act
    Medicare
      Prescription Drug, Improvement and Modernization Act of
    2003MISO
    Midwest
      Independent Transmission System Operator,
Inc.
 
   i
 GLOSSARY
OF TERMS, Cont.  
 Moody’s
    Moody’s
      Investors ServiceMW
    MegawattsNAAQS
    National
      Ambient Air Quality StandardsNERC
    North
      American Electric Reliability CouncilNOAC
    Northwest
      Ohio Aggregation CoalitionNOV
    Notices of
      ViolationNOX
    Nitrogen
      OxideNRC
    Nuclear
      Regulatory CommissionOCC
    Ohio
      Consumers' CounselOCI
    Other
      Comprehensive IncomeOPEB
    Other
      Post-Employment BenefitsPJM
    PJM
      Interconnection L.L.C.PLR
    Provider of
      Last ResortPPUC
    Pennsylvania
      Public Utility CommissionPUCO
    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
      143
    SFAS No. 143,
      "Accounting for Asset Retirement Obligations"SFAS
      144
    SFAS No. 144,
      "Accounting for the Impairment or Disposal of Long-Lived
      Assets"SFAS
      150
    SFAS No. 150,
      "Accounting for Certain Financial Instruments with Characteristics of Both
      Liabilities
      and Equity"SO2
    Sulfur
      DioxideSPE
    Special
      Purpose EntityVIE
    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 auditors’ 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 Ohio
Edison Company:





We have completed
an integrated audit of Ohio 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 Ohio Edison Company and its subsidiaries at December 31, 2004 and 2003, and
the results of their operations and their cash flows for each of the three years
in the period ended December 31, 2004 in conformity with accounting principles
generally accepted in the United States of America. These financial statements
are the responsibility of the Company’s management. Our responsibility is to
express an opinion on these financial statements based on our audits. We
conducted our audits of these statements in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those standards
require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit of
financial statements includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.





As discussed in
Note 2(G) to the consolidated financial statements, the Company changed its
method of accounting for asset retirement obligations as of January 1, 2003. As
discussed in Note 7 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








**OHIO EDISON
COMPANY**





**SELECTED
FINANCIAL DATA**








**2004**
    
    **2003**
    
    **2002**
    
    **2001**
    
    **2000*****(Dollars
      in thousands)***Operating
      Revenues
    
    $
    2,945,583
    
    $
    2,925,310
    
    $
    2,948,675
    
    $
    3,056,464
    
    $
    2,726,708Operating
      Income
    
    $
    335,529
    
    $
    336,936
    
    $
    453,831
    
    $
    466,819
    
    $
    482,321Income Before
      Cumulative Effect of
      Accounting
      Change
    
    $
    342,766
    
    $
    292,925
    
    $
    356,159
    
    $
    350,212
    
    $
    336,456Net
      Income
    
    $
    342,766
    
    $
    324,645
    
    $
    356,159
    
    $
    350,212
    
    $
    336,456Earnings on
      Common Stock
    
    $
    340,264
    
    $
    321,913
    
    $
    349,649
    
    $
    339,510
    
    $
    325,332Total
      Assets
    
    $
    6,482,651
    
    $
    7,316,930
    
    $
    7,790,041
    
    $
    7,915,953
    
    $
    8,154,151**Capitalization
      as of December 31:**Common
      Stockholder's Equity
    
    $
    2,493,809
    
    $
    2,582,970
    
    $
    2,839,255
    
    $
    2,671,001
    
    $
    2,556,992Preferred
      Stock:Not Subject
      to Mandatory Redemption
    
    
    100,070
    
    
    100,070
    
    
    100,070
    
    
    200,070
    
    
    200,070Subject to
      Mandatory Redemption
    
    
    --
    
    
    --
    
    
    13,500
    
    
    134,250
    
    
    135,000Long-Term
      Debt and Other Long-Term Obligations
    
    
    1,114,914
    
    
    1,179,789
    
    
    1,219,347
    
    
    1,614,996
    
    
    2,000,622Total
      Capitalization
    
    $
    3,708,793
    
    $
    3,862,829
    
    $
    4,172,172
    
    $
    4,620,317
    
    $
    4,892,684**Capitalization
      Ratios:**Common
      Stockholder's Equity
    
    
    67.2
    %
    
    66.9
    %
    
    68.1
    %
    
    57.8
    %
    
    52.3
    %Preferred
      Stock:Not Subject
      to Mandatory Redemption
    
    
    2.7
    
    
    2.6
    
    
    2.4
    
    
    4.3
    
    
    4.1Subject to
      Mandatory Redemption
    
    
    --
    
    
    --
    
    
    0.3
    
    
    2.9
    
    
    2.7Long-Term
      Debt and Other Long-Term Obligations
    
    
    30.1
    
    
    30.5
    
    
    29.2
    
    
    35.0
    
    
    40.9Total
      Capitalization
    
    
    100.0
    %
    
    100.0
    %
    
    100.0
    %
    
    100.0
    %
    
    100.0
    %**Distribution
      KWH Deliveries (Millions):**Residential
    
    
    10,180
    
    
    10,009
    
    
    10,233
    
    
    9,646
    
    
    9,432Commercial
    
    
    8,276
    
    
    8,105
    
    
    7,994
    
    
    7,967
    
    
    8,221Industrial
    
    
    10,700
    
    
    10,658
    
    
    10,672
    
    
    10,995
    
    
    11,631Other
    
    
    144
    
    
    160
    
    
    154
    
    
    152
    
    
    151Total
    
    
    29,300
    
    
    28,932
    
    
    29,053
    
    
    28,760
    
    
    29,435**Customers
      Served:**Residential
    
    
    1,056,560
    
    
    1,044,419
    
    
    1,041,825
    
    
    1,033,414
    
    
    1,014,379Commercial
    
    
    129,017
    
    
    127,856
    
    
    119,771
    
    
    118,469
    
    
    116,931Industrial
    
    
    1,149
    
    
    1,182
    
    
    4,500
    
    
    4,573
    
    
    4,569Other
    
    
    1,751
    
    
    1,752
    
    
    1,756
    
    
    1,664
    
    
    1,606Total
    
    
    1,188,477
    
    
    1,175,209
    
    
    1,167,852
    
    
    1,158,120
    
    
    1,137,485**Number
      of Employees**
    
    
    1,370
    
    
    1,521
    
    
    1,569
    
    
    1,618
    
    
    1,647








3





**OHIO 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 as disclosed in
our Securities and Exchange Commission filings, generally, 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 in 2004 increased to $340 million from $322 million in 2003. Earnings on
common stock in 2003 included an af ter-tax gain of $32
million from the cumulative effect of an accounting change due to the adoption
of SFAS 143 (see Note 2(G)). Income before the cumulative effect of an
accounting change was $293 million in 2003. The earnings increase in 2004
primarily resulted from lower nuclear operating costs and reduced financing
costs, partially offset by higher purchased power costs compared to 2003.
Earnings in 2003 decreased to $322 million from $350 million in 2002. The
decrease primarily resulted from increased nuclear outage related costs,
increased amortization of the Ohio transition regulatory assets and reduced
operating revenues. These items were partially offset by reduced nuclear fuel
expenses as a result of the additional nuclear outages, reduced financing costs
and the after-tax credit from the 2003 cumulative effect of an accounting
change.


Operating revenues
increased by $20 million (0.7%) in 2004 compared with 2003 primarily due to
increases of $22 million in wholesale sales and $12 million in retail
generation revenues partially offset by $16 million shopping incentive credits
discussed below. Revenues from wholesale sales to FES (resulting from increased
nuclear generation available for sale) increased by $29 million, and was
partially offset by $10 million of lower revenues due to the expiration of
a contract in July 2003. The higher retail generation revenues primarily
resulted from a $9 million increase in sales to industrial customers, reflecting
a 1.1 percentage point decrease in electric generation services provided by
alternative suppliers as a percent of total sales delivered in our service
areas. Revenues from sales to residential customers decreased by $2 million as
the corresponding percentage for shopping increased by 2.5 percentage
points. Commercial sector revenues increased by $5 million due to higher KWH
sales and unit prices -- the percentage of customers shopping remained
relatively unchanged.





Operating revenues
decreased by $23 million (0.8%) in 2003 compared with 2002 due to
cooler-than-normal temperatures in the second and third quarters of 2003 and
increased sales by alternative suppliers. The lower revenues primarily resulted
from reduced generation sales revenues, which included all retail customer
categories - residential, commercial and industrial. KWH sales to retail
customers declined by 8.1% in 2003 from the prior year, reducing generation
sales revenue by $98 million. Electric generation services provided to retail
customers by alternative suppliers as a percent of total KWH delivered in the
franchise area increased 6.1 percentage points in 2003 from 2002. Sales revenues
from wholesale customers increased by $47 million in 2003 compared with 2002.
This increase resulted from higher unit prices, partially offset by lower KWH
sales to FES due to reduced nuclear generation available for sale.





4





Revenues from
distribution throughput increased $3 million in 2004 compared with 2003.
Distribution deliveries to commercial customers increased by $11 million in 2004
compared to 2003, reflecting increased KWH deliveries (2.1%) and higher unit
prices. Lower unit prices offset the effect of higher throughput resulting in a
decrease of $9 million in revenues from industrial customers. The increased
sales to the commercial and industrial sectors resulted from the improving
economy in our service areas. Revenues from distribution throughput increased by
$35 million in 2003 for all retail customer - classes compared with 2002,
primarily due to higher unit prices partially offset by the effects of slightly
lower KWH deliveries in 2003.





Under the Ohio
transition plan, we provide incentives to customers to encourage switching to
alternative energy providers - $16 million of additional credits in 2004
compared to $8 million of additional credits in 2003 from 2002. These revenue
reductions are deferred for future recovery under OE’s transition plan and do
not affect current period earnings.





Changes in electric
generation sales and distribution deliveries in 2004 and 2003 from the prior
year are summarized in the following table:




**Changes
      in KWH Sales*****Increase
      (Decrease)***
    
    **2004**
    
    **2003**Electric
      Generation:Retail
    
    
    0.5
    %
    
    (8.1
    )%Wholesale
    
    
    7.3
    %
    
    (10.5
    )%Total
      Electric Generation Sales
    
    
    3.7
    %
    
    (9.2
    )%Distribution
      Deliveries:Residential
    
    
    1.7
    %
    
    (2.2
    )%Commercial
    
    
    2.1
    %
    
    1.4
    %Industrial
    
    
    0.4
    %
    
    (0.1
    )%Total
      Distribution Deliveries
    
    
    1.3
    %
    
    (0.4
    )%
   *Operating
Expenses and Taxes*





Total operating
expenses and taxes increased by $22 million in 2004 and by $94 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
    
    $
    4
    
    $
    (3
    )Purchased
      power costs
    
    
    56
    
    
    (17
    )Nuclear
      operating costs
    
    
    (57
    )
    
    80Other
      operating costs
    
    
    (27
    )
    
    --Provision for
      depreciation
    
    
    5
    
    
    (24
    )Amortization
      of regulatory assets
    
    
    18
    
    
    58Deferral of
      new regulatory assets
    
    
    (27
    )
    
    19General
      taxes
    
    
    10
    
    
    (7
    )Income
      taxes
    
    
    40
    
    
    (12
    )**Total
      operating expenses and taxes**
    
    **$**
    **22**
    
    **$**
    **94**








Higher fuel costs
in 2004 compared to 2003, resulted from increased nuclear generation - up 13.1%.
Purchased power costs were higher in 2004 due to higher unit costs. Lower
nuclear operating costs in 2004 were primarily the result of one scheduled
refueling outage in 2004 compared to three scheduled refueling outages in 2003.
The decrease in other operating costs in 2004 compared to 2003 was due to
reduced labor costs and lower employee benefits expenses.





Lower fuel costs in
2003 compared to 2002 resulted from reduced nuclear generation - down 10.5%. In
2003, the KWH purchase requirements were lower than in 2002 because of reduced
electric generation sales - those cost reductions were partially offset by the
effect of higher unit costs. Higher nuclear operating costs in 2003 were driven
by three nuclear refueling outages compared with one refueling outage in 2002.
The Beaver Valley Unit 1 and Perry refueling outages in 2003 included additional
unplanned work, which extended the length of the outages and increased their
cost.





5





Provision for
depreciation increased in 2004 compared to 2003 primarily due to a slight change
in the composite depreciation rate and a higher depreciable asset base.
Decreased depreciation charges in 2003 compared to 2002 were primarily due to
lower charges resulting from the implementation of SFAS 143 ($19 million).
Increases in amortization of regulatory assets in 2004 and 2003 compared to the
prior year relates to higher amortization of Ohio transition regulatory assets.
The higher deferrals of new regulatory assets in 2004 compared to 2003 primarily
relates to higher shopping incentive deferrals ($16 million) and deferred
interest on shopping incentives ($10 million). The decrease in deferrals in 2003
from 2002 was due to reduced tax-related deferrals ($27 million) partially
offset by higher shopping incentive deferrals ($8 million).





General taxes
increased by $10 million in 2004 and decreased by $7 million in 2003, primarily
due to a property tax settlement in 2003. In 2003, the tax settlement was
partially offset by higher KWH excise taxes.





*Other
Income*





Other income
increased $7 million in 2004 compared to 2003, primarily due to gains on
disposition of property. In 2003, other income increased by $24 million
from the prior year, primarily due to the absence in 2003 of charges in 2002
related to low-income housing investments.





*Net Interest
Charges*





Net interest
charges continued to trend lower, decreasing by $44 million in 2004 and $30
million in 2003. We continued to redeem and refinance outstanding debt during
2004 - net redemptions and refinancing activities totaled $121 million and
$245 million, respectively.





*Cumulative
Effect of Accounting Change*





Upon adoption of
SFAS 143 in the first quarter of 2003, we recorded an after-tax credit to net
income of $32 million. The cumulative adjustment for unrecognized
depreciation, accretion offset by the reduction in the existing decommissioning
liabilities and ceasing the accounting practice of depreciating non-regulated
generation assets using a cost of removal component was a $54 million increase
to income, or $32 million net of income taxes.





**Capital
Resources and Liquidity**





Our cash
requirements in 2004 for operating expenses, construction expenditures,
scheduled debt maturities and preferred stock redemptions were met without
increasing our net debt and preferred stock outstanding. During 2005, we expect
to meet our contractual obligations with cash from operations. Thereafter, we
expect to use a combination of cash from operations and funds from the capital
markets.





*Changes in Cash
Position*





As of
December 31, 2004, we had $1 million 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.





*Cash Flows From
Operating Activities*





Cash provided from
operating activities during 2004, 2003 and 2002 are as follows:








**Operating
      Cash Flows**
    
    **2004**
    
    **2003**
    
    **2002*****(In
      millions)***Cash earnings(1)
    
    $
    776
    
    $
    689
    
    $
    743Pension trust
      contribution(2)
    
    
    (44
    )
    
    --
    
    
    --Working
      capital and other
    
    
    (312
    )
    
    371
    
    
    330Total
    
    $
    420
    
    $
    1,060
    
    $
    1,073





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


(2)  Pension trust
contribution net of $29 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.





6




**Reconciliation
      of Cash Earnings**
    
    **2004**
    
    **2003**
    
    **2002*****(In
      millions)***Net Income
      (GAAP)
    
    $
    343
    
    $
    325
    
    $
    356Non-Cash
      Charges (Credits):Provision for
      depreciation
    
    
    122
    
    
    118
    
    
    142Amortization
      of regulatory assets
    
    
    411
    
    
    393
    
    
    336Nuclear fuel
      and capital lease amortization
    
    
    43
    
    
    39
    
    
    48Deferral of
      new regulatory assets
    
    
    (101
    )
    
    (73
    )
    
    (92
    )Deferred
      income taxes and investment tax credits, net
    
    
    (73
    )
    
    (88
    )
    
    (76
    )Cumulative
      effect of accounting change
    
    
    --
    
    
    (54
    )
    
    --Other
      non-cash charges
    
    
    31
    
    
    29
    
    
    29Cash earnings
      (Non-GAAP)
    
    $
    776
    
    $
    689
    
    $
    743





Net cash from
operating activities decreased $640 million in 2004 compared to 2003 due to a
$683 million decrease from changes in working capital and a $44 million
after-tax voluntary pension trust contribution. These decreases were partially
offset by a $87 million increase in cash earnings as described above under
“Results from Operations”. The change in working capital primarily reflects
decreases in accounts payable and accrued tax balances. In 2004 tax liabilities
among affiliated companies were settled in accordance with the tax sharing
agreement, reducing our accrued taxes by $249 million. Accrued taxes were also
reduced by a $169 million federal income tax payment in 2004.





Net cash provided
from operating activities decreased $13 million in 2003 compared to 2002 due to
a $54 million decrease from cash earnings as described under "Results of
Operations" partially offset by a $41 million increase in working capital
requirements. The increase in working capital requirements primarily represents
changes in receivables partially offset by decreased accounts payable and
accrued tax balances.





*Cash Flows From
Financing Activities*


In 2004, 2003 and
2002, net cash used for financing activities of $569 million, $982 million and
$599 million, respectively, primarily reflect debt redemptions and common stock
dividend payments to FirstEnergy. The following table provides details regarding
new issues and redemptions during each year:





**Securities
      Issued or Redeemed**
    
    **2004**
    
    **2003**
    
    **2002*****(In
      millions)******New
      Issues***Pollution
      Control Notes
    
    $
    30
    
    $
    --
    
    $
    15Unsecured
      Notes
    
    
    --
    
    
    325
    
    
    --Long-Term
      Revolving Credit
    
    
    --
    
    
    40
    
    
    --$
    30
    
    $
    365
    
    $
    15**Redemptions**First
      Mortgage Bonds
    
    $
    63
    
    $
    410
    
    $
    280Pollution
      Control Notes
    
    
    --
    
    
    30
    
    
    15Secured
      Notes
    
    
    62
    
    
    62
    
    
    127Preferred
      Stock
    
    
    1
    
    
    1
    
    
    221Long-Term
      Revolving Credit
    
    
    40
    
    
    --
    
    
    --Other,
      principally redemption premiums
    
    
    6
    
    
    17
    
    
    4$
    172
    
    $
    520
    
    $
    647Short-term
      Borrowings, Net (use)/source of cash
    
    $
    (4
    )
    $
    (225
    )
    $
    162





Net cash used for
financing activities increased to $569 million in 2004 from $982 million in
2003. The decrease resulted from a net reduction of $234 million of debt
refinancings and a $178 million reduction of common stock dividends to
FirstEnergy. The $383 million increase in net cash used for financing activities
in 2003 from 2002 was principally due to a $477 million increase in dividends to
FirstEnergy partially offset by a $90 million decrease in net debt redemptions.





On June 7,
2004, we replaced certain collateralized LOCs that were issued in 1994 in
support of our obligations to lessors under the Beaver Valley Unit 2 sale and
leaseback arrangements. Approximately $289 million in cash collateral and
accrued interest previously held by OES Finance Incorporated, our wholly owned
subsidiary, was released on July 15, 2004 upon cancellation of the existing
LOCs and was used primarily to repay short-term debt. Simultaneously with the
issuance of the replacement LOCs, OE entered into a Credit Agreement pursuant to
which a standby LOC was issued in support of the replacement LOCs, and the
issuer of the LOCs obtained the right to pledge or assign participations in our
reimbursement obligations to a trust. The trust then issued and sold trust
certificates to institutional investors that were designed to be the credit
equivalent of an investment directly in OE.





7





We had
approximately $540 million of cash and temporary investments (which include
short-term notes receivable from associated companies) and approximately $179
million of short-term indebtedness as of December 31, 2004. Available borrowing
capability under bilateral bank facilities totaled $13 million as of December
31, 2004. We have obtained authorization from the PUCO to incur short-term debt
of up to $500 million (including bank facilities and the utility money pool
described below). Penn has obtained authorization from the SEC to incur
short-term debt up to its charter limit of $51 million (including the utility
money pool). At the end of 2004, we had the aggregate capability to issue
approximately $2.0 billion of additional FMB on the basis of property additions
and retired bonds under the terms of our mortgage indentures. The issuance of
FMB by us is also subject to provisions of our senior note indentures generally
limiting the incurrence of additional secured debt, subject to certain
exceptions that would permit, among other things, the issuance of secured debt
(including FMB) (i) supporting pollution control notes or similar obligations,
or (ii) as an extension, renewal or replacement of previously outstanding
secured debt. In addition, these provisions would permit us to incur additional
secured debt not otherwise permitted by a specified exception of up to $641
million, as of December 31, 2004. The OE Companies could issue a total of
$3.2 billion of preferred stock (assuming no additional debt was issued) as of
the end of 2004.





Our $125 million
364-day revolving credit facility was restructured through a new syndicated
FirstEnergy facility that was completed on June 22, 2004. Combined with our
existing syndicated $125 million three-year facility maturing in October 2006,
our existing syndicated $250 million two-year facility maturing in May 2005 and
bank facilities of $34 million, our credit facilities total $409 million,
of which $388 million was unused as of December 31, 2004. These facilities
are intended to provide liquidity to meet our short-term working capital
requirements and would be available for investment in the money pool with our
regulated affiliates.





Borrowings under
these facilities are conditioned on maintaining compliance with certain
financial covenants in the agreement. Under our $125 million 364-day and $250
million two-year facilities, we are required to maintain a debt to total
capitalization ratio of no more than 0.65 to 1 and a contractually-defined fixed
charge coverage ratio of no less than 2 to 1. We are in compliance with these
financial covenants. As of December 31, 2004, our fixed charge coverage
ratio, as defined under the credit agreements, was 7.15 to 1. Our debt to total
capitalization ratio, as defined under the credit agreements, was 0.39 to 1. The
ability to draw on these facilities is also conditioned upon our making certain
representations and warranties to the lending banks prior to drawing on its
facilities, including a representation that there has been no material adverse
change in our business, condition (financial or otherwise), results of
operations, or prospects.





Our primary credit
facilities contain no provisions restricting our ability to borrow, or
accelerating repayment of outstanding loans, as a result of any change in our
S&P or Moody's credit ratings. The primary facilities do contain “pricing
grids”, whereby the cost of funds borrowed under the facilities is related to
our credit ratings.





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 the respective regulated subsidiaries, as well
as proceeds available from bank borrowings. For the regulated companies,
available bank borrowings include $1.75 billion from FirstEnergy’s and our
revolving credit facilities. Companies receiving a loan under the money pool
agreements must repay the principal amount of the loan, together with accrued
interest, within 364 days of borrowing the funds. The rate of interest is the
same for each company receiving a loan from the pool and is based on the average
cost of funds available through the pool. The average interest rate for
borrowings under these arrangements in 2004 was 1.43%.





In March 2004, Penn
completed receivables financing arrangement that provides borrowing capability
of up to $25 million. The borrowing rate is based on bank commercial paper
rates. Penn is required to pay an annual facility fee of 0.40% on the entire
finance limit. The facility was undrawn as of December 31, 2004 and matures
on March 29, 2005. Penn plans to renew the agreement. On December 1, 2004,
Ohio Air Quality Development Authority Series 1999-C pollution control notes
aggregating $47,725,000 were remarketed in a Dutch Auction interest mode,
insured with municipal bond insurance and secured with first mortgage
bonds.





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.





8








**Ratings
      of Securities****Securities**
    
    **S&P**
    
    **Moody’s**
    
    **Fitch****FirstEnergy**
    
    
    Senior
      unsecured
    
    
    BB+
    
    
    Baa3
    
    
    BBB-**Ohio
      Edison**
    
    
    Senior
      secured
    
    
    BBB
    
    
    Baa1
    
    
    BBB+Senior
      unsecured
    
    
    BB+
    
    
    Baa2
    
    
    BBBPreferred
      stock
    
    
    BB
    
    
    Ba1
    
    
    BBB-**Penn**
    
    
    Senior
      secured
    
    
    BBB
    
    
    Baa1
    
    
    BBB+Senior
      unsecured(1)
    
    
    BB+
    
    
    Baa2
    
    
    BBBPreferred
      stock
    
    
    BB
    
    
    Ba1
    
    
    BBB-


(1)
    Penn's only
      senior unsecured debt obligations are notes underlying pollution control
      revenue refunding bonds issued by the Ohio Air Quality Development
      Authority to which bonds this rating applies


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 provided
from investing activities totaled $149 million in 2004 compared to $97 million
used for investing activities in 2003. The $246 million change resulted
primarily from $278 million of cash proceeds from certificates of deposit in the
third quarter of 2004 and a $62 million increase in loan repayments from
associated companies. These increases were offset by a $46 million increase in
property additions. Net cash used for investing activities in 2003 decreased by
$362 million from 2002. The decrease was primarily due to a $394 million
increase in cash payments received on long-term notes receivable offset by a $40
million increase in property additions.




Our capital
spending for the period 2005-2007 is expected to be about $667 million
(excluding nuclear fuel), of which approximately $215 million applies to 2005.
Investments for additional nuclear fuel during the 2005-2007 period are
estimated to be approximately $138 million, of which about $34 million applies
to 2005. During the same period, our nuclear fuel investments are expected to be
reduced by approximately $125 million and $41 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 are as follows:








**2006-**
    
    **2008-****Contractual
      Obligations**
    
    **Total**
    
    **2005**
    
    **2007**
    
    **2009**
    
    **Thereafter*****(In
      millions)***Long-term
      debt (4)
    
    $
    1,504
    
    $
    134
    
    $
    12
    
    $
    181
    
    $
    1,177Short-term
      borrowings
    
    
    179
    
    
    179
    
    
    --
    
    
    --
    
    
    --Preferred
      stock (1)
    
    
    13
    
    
    1
    
    
    12
    
    
    --
    
    
    --Capital
      leases
    
    
    11
    
    
    4
    
    
    5
    
    
    1
    
    
    1Operating
      leases (2)
    
    
    1,158
    
    
    82
    
    
    160
    
    
    203
    
    
    713Purchases
      (3)
    
    
    194
    
    
    34
    
    
    101
    
    
    59
    
    
    --Total
    
    $
    3,059
    
    $
    434
    
    $
    290
    
    $
    444
    
    $
    1,891





(1)
    Subject to
      mandatory redemption.


(2)
    Operating
      lease payments are net of capital trust receipts of $532.4 million (see
      Note 6).


(3)
    Fuel and
      power purchases under contracts with fixed or minimum quantities and
      approximate timing.
(4)
    Amounts
      reflected do not include interest on long-term
debt.





9





**Off-Balance
Sheet Arrangements**





We have
o bligations that are
not included on our Consolidated Balance Sheets related to the sale and
leaseback arrangements involving Perry Unit 1 and Beaver Valley Unit 2, which
are reflected as part of the operating lease payments disclosed above (see Note
6 - Leases). The present value of these operating lease commitments, net of
trust investments, was $673 million 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, as noted in the following table which presents principal amounts and
related weighted average interest rates by year of maturity for our investment
portfolio, debt obligations and preferred stock with mandatory redemption
provisions.








**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 Cashand Cash
      Equivalents-Fixed
      Income
    
    $
    31
    
    $
    36
    
    $
    39
    
    $
    17
    
    $
    26
    
    $
    639
    
    **$**
    **788**
    
    **$**
    **887**Average
      interest rate
    
    
    8.0
    %
    
    8.1
    %
    
    8.2
    %
    
    8.2
    %
    
    8.5
    %
    
    7.2
    %
    
    7.4
    %Liabilities
      Long-term
      Debt and OtherLong-Term
      Obligations:Fixed
      rate
    
    $
    134
    
    $
    6
    
    $
    6
    
    $
    179
    
    $
    2
    
    $
    466
    
    **$**
    **793**
    
    **$**
    **816**Average
      interest rate
    
    
    7.2
    %
    
    7.9
    %
    
    7.9
    %
    
    4.1
    %
    
    8.0
    %
    
    6.0
    %
    
    5.8
    %Variable
      rate
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    711
    
    **$**
    **711**
    
    **$**
    **712**Average
      interest rate
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2.1
    %
    
    2.1
    %Preferred
      Stock Subject to
      Mandatory
      Redemption
    
    $
    1
    
    $
    1
    
    $
    11
    
    
    
    
    
    
    
    
    
    
    **$**
    **13**
    
    **$**
    **12**Average
      dividend rate
    
    
    7.6
    %
    
    7.6
    %
    
    7.6
    %
    
    
    
    
    
    
    
    
    
    
    7.6
    %Short-term
      Borrowings
    
    
    179
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    **$**
    **179**
    
    **$**
    **179**Average
      interest rate
    
    
    2.3
    %
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2.3
    %








**Equity
Price Risk**





Included in our
nuclear decommissioning trust investments are marketable equity securities
carried at their market value of approximately $248 million and $208 million as
of December 31, 2004 and 2003, respectively. A hypothetical 10% decrease in
prices quoted by stock exchanges would result in a $25 million reduction in fair
value as of December 31, 2004 (see Note 5 - 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. In Ohio and Pennsylvania, 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 Ohio 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 for OE customers), and the
customer receives a generation charge from the alternative supplier. OE has
continuing PLR responsibility to its franchise customers through
December 31, 2005.





10





Regulatory assets
are costs which have been authorized by the PUCO, the PPUC 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. All
regulatory assets are expected to be recovered under the provisions of our
transition plan and rate restructuring plan. Our regulatory assets were as
follows:





**Regulatory
      Assets as of December 31,****Company**
    
    **2004***
    
    **2003*****(In
      millions)***Ohio
      Edison
    
    $
    1,116
    
    $
    1,450Penn
    
    
    --
    
    
    28Consolidated
      Total
    
    $
    1,116
    
    $
    1,478





* Changes in Penn's
net regulatory asset components in 2004 resulted in net regulatory liabilities
of approximately $18 million


included in Other Noncurrent Liabilities on the Consolidated Balance
Sheet as of December 31, 2004.







As part of our Ohio
transition plan, we are obligated to supply electricity to customers who do not
choose an alternative supplier. The Company is also required to provide 560 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
      our amortization period for transition costs being recovered through the
      RTC from 2006 to as late as 2007;·
    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.


On
December 30, 2004, we filed an application with the PUCO seeking tariff
adjustments to recover increases of approximately $14 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 and Pennsylvania.





*Environmental
Matters*

We believe we are
in compliance with current SO2 and NOx reduction
requirements under the Clean Air Act Amendments of 1990. In 1998, the EPA
finalized regulations requiring additional NOx reductions from our
Ohio and Pennsylvania facilities. Various regulatory and judicial actions have
since sought to further define NOx reduction requirements. We continue to
evaluate our compliance plans and other compliance
options.





11




*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 NOxreductions from our facilities. The EPA's NOx Transport Rule
imposes uniform reductions of NOxemissions (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 NOxemissions are contributing significantly to ozone levels in the eastern
United States. We believe their facilities are also complying with
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.
 
 *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.


**


*W. H. Sammis Plant-*


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





12





*Regulation of
Hazardous Waste-*


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


*Climate
Change-*





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




We cannot currently
estimate the financial impact of climate change policies, although the potential
restrictions on CO2 emissions could require significant capital and
other expenditures. However, the CO2 emissions per KWH of electricity
we generated 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.





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 us. 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.





13





*Other Legal
Matters-*


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


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 35.24% interest. Although the NRC noted that the plant continues to
operate safely, the agency has indicated that its increased oversight will
include an extensive NRC team inspection to assess the equipment problems and
the sufficiency of FENOC's corrective actions. The outcome of these matters
could include NRC enforcement action or other impacts on operating authority. As
a result, these matters could have a material adverse effect on FirstEnergy's or
its subsidiaries' financial condition.





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 OE, and the Davis-Besse extended outage (we have no interest in
Davis-Besse), 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.





*Regulatory
Accounting*





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





*Revenue
Recognition*





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





*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.





14




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 $73 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 $48 million. As
prescribed by SFAS 87, we increased our additional minimum liability by $18
million, recording an increase in an intangible asset of $5 million and charging
$13 million to OCI. The balance in AOCL of $69 million (net of $49 million in
deferred taxes) will reverse in future periods to the extent the fair value of
trust assets exceeds the accumulated benefit obligation.





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





*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 had not yet been incurred. 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 Stablization 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 judgment about future
events. The aggregate amount of cash flows determines whether an impairment is
indicated. The timing of the cash flows is critical in determining the amount of
the impairment.





15





*Nuclear
Decommissioning*





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





**New
Accounting Standards and Interpretations**





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





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








16





**OHIO EDISON
COMPANY**





**CONSOLIDATED
STATEMENTS OF INCOME**








**For
      the Years Ended December 31,**
    
    **2004**
    
    **2003**
    
    **2002*****(In
      thousands)*****OPERATING
      REVENUES (Note 2(I))**
    
    $
    2,945,583
    
    $
    2,925,310
    
    $
    2,948,675**OPERATING
      EXPENSES AND TAXES:**Fuel
    
    
    56,560
    
    
    52,169
    
    
    55,337Purchased
      power (Note 2(I))
    
    
    970,670
    
    
    914,723
    
    
    931,400Nuclear
      operating costs
    
    
    375,309
    
    
    432,315
    
    
    352,129Other
      operating costs (Note 2(I))
    
    
    336,772
    
    
    363,989
    
    
    364,436Provision for
      depreciation
    
    
    122,413
    
    
    117,895
    
    
    142,083Amortization
      of regulatory assets
    
    
    411,326
    
    
    393,409
    
    
    335,523Deferral of
      new regulatory assets
    
    
    (100,633
    )
    
    (73,183
    )
    
    (92,086
    )General
      taxes
    
    
    180,523
    
    
    170,078
    
    
    177,021Income
      taxes
    
    
    257,114
    
    
    216,979
    
    
    229,001Total
      operating expenses and taxes
    
    
    2,610,054
    
    
    2,588,374
    
    
    2,494,844**OPERATING
      INCOME**
    
    
    335,529
    
    
    336,936
    
    
    453,831**OTHER
      INCOME (Note 2(I))**
    
    
    74,077
    
    
    66,782
    
    
    42,859**NET
      INTEREST CHARGES:**Interest on
      long-term debt
    
    
    59,465
    
    
    91,068
    
    
    119,123Allowance for
      borrowed funds used during
      construction
      and capitalized interest
    
    
    (7,211
    )
    
    (6,075
    )
    
    (3,639
    )Other
      interest expense
    
    
    12,026
    
    
    22,340
    
    
    14,598Subsidiary's
      preferred stock dividend requirements
    
    
    2,560
    
    
    3,460
    
    
    10,449Net interest
      charges
    
    
    66,840
    
    
    110,793
    
    
    140,531**INCOME
      BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE**
    
    
    342,766
    
    
    292,925
    
    
    356,159Cumulative
      effect of accounting change (net of income taxes of
      $22,389,000)
      (Note 2(G))
    
    
    --
    
    
    31,720
    
    
    --**NET
      INCOME**
    
    
    342,766
    
    
    324,645
    
    
    356,159**PREFERRED
      STOCK DIVIDEND REQUIREMENTS**
    
    
    2,502
    
    
    2,732
    
    
    6,510**EARNINGS
      ON COMMON STOCK**
    
    $
    340,264
    
    $
    321,913
    
    $
    349,649











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





17





**OHIO EDISON
COMPANY**





**CONSOLIDATED
BALANCE SHEETS**





**As of
      December 31,**
    
    **2004**
    
    **2003*****(In
      thousands)*****ASSETS****UTILITY
      PLANT:**In
      service
    
    $
    5,440,374
    
    $
    5,269,042Less-Accumulated
      provision for depreciation
    
    
    2,716,851
    
    
    2,578,8992,723,523
    
    
    2,690,143Construction
      work in progress-Electric
      plant
    
    
    203,167
    
    
    145,380Nuclear
      fuel
    
    
    21,694
    
    
    554224,861
    
    
    145,9342,948,384
    
    
    2,836,077**OTHER
      PROPERTY AND INVESTMENTS:**Investment in
      lease obligation bonds (Note 6)
    
    
    354,707
    
    
    383,510Certificates
      of deposit (Note 9(C))
    
    
    --
    
    
    277,763Nuclear plant
      decommissioning trusts
    
    
    436,134
    
    
    376,367Long-term
      notes receivable from associated companies
    
    
    208,170
    
    
    508,594Other
    
    
    48,579
    
    
    59,1021,047,590
    
    
    1,605,336**CURRENT
      ASSETS:**Cash and cash
      equivalents
    
    
    1,230
    
    
    1,883Receivables-Customers
      (less accumulated provisions of $6,302,000 and $8,747,000,respectively,
      for uncollectible accounts)
    
    
    274,304
    
    
    280,538Associated
      companies
    
    
    245,148
    
    
    436,991Other (less
      accumulated provision of $64,000 and $2,282,000,
      respectively,
      for uncollectible accounts)
    
    
    18,385
    
    
    28,308Notes
      receivable from associated companies
    
    
    538,871
    
    
    366,501Materials and
      supplies, at average cost
    
    
    90,072
    
    
    79,813Prepayments
      and other
    
    
    13,104
    
    
    14,3901,181,114
    
    
    1,208,424**DEFERRED
      CHARGES:**Regulatory
      assets
    
    
    1,115,627
    
    
    1,477,969Property
      taxes
    
    
    61,419
    
    
    59,279Unamortized
      sale and leaseback costs
    
    
    60,242
    
    
    65,631Other
    
    
    68,275
    
    
    64,2141,305,563
    
    
    1,667,093$
    6,482,651
    
    $
    7,316,930**CAPITALIZATION
      AND LIABILITIES****CAPITALIZATION**(See
      Consolidated Statements of Capitalization):Common
      stockholder's equity
    
    $
    2,493,809
    
    $
    2,582,970Preferred
      stock not subject to mandatory redemption
    
    
    60,965
    
    
    60,965Preferred
      stock of consolidated subsidiary not subject to mandatory
      redemption
    
    
    39,105
    
    
    39,105Long-term
      debt and other long-term obligations
    
    
    1,114,914
    
    
    1,179,7893,708,793
    
    
    3,862,829**CURRENT
      LIABILITIES:**Currently
      payable long-term debt
    
    
    398,263
    
    
    466,589Short-term
      borrowings-Associated
      companies
    
    
    11,852
    
    
    11,334Other
    
    
    167,007
    
    
    171,540Accounts
      payable-Associated
      companies
    
    
    187,921
    
    
    271,262Other
    
    
    10,582
    
    
    7,979Accrued
      taxes
    
    
    153,400
    
    
    560,345Accrued
      interest
    
    
    11,992
    
    
    18,714Other
    
    
    62,671
    
    
    58,6801,003,688
    
    
    1,566,443**NONCURRENT
      LIABILITIES:**Accumulated
      deferred income taxes
    
    
    766,276
    
    
    867,691Accumulated
      deferred investment tax credits
    
    
    62,471
    
    
    75,820Asset
      retirement obligation
    
    
    339,134
    
    
    317,702Retirement
      benefits
    
    
    307,880
    
    
    331,829Other
    
    
    294,409
    
    
    294,6161,770,170
    
    
    1,887,658**COMMITMENTS
      AND CONTINGENCIES**(Notes 6 and
      12)$
    6,482,651
    
    $
    7,316,930
 
 The accompanying
Notes to Consolidated Financial Statements are an integral part of these balance
sheets.










18





**OHIO EDISON
COMPANY**





**CONSOLIDATED
STATEMENTS OF CAPITALIZATION**








**As
      of December 31,**
    
    **2004**
    
    **2003*****(Dollars
      in thousands, except per share amounts)*****COMMON
      STOCKHOLDER'S EQUITY:**Common stock,
      without par value, authorized 175,000,000 shares-100 shares
      outstanding
    
    $
    2,098,729
    
    $
    2,098,729Accumulated
      other comprehensive loss (Note 2(F))
    
    
    (47,118
    )
    
    (38,693
    )Retained
      earnings (Note 9(A))
    
    
    442,198
    
    
    522,934Total
      common stockholder's equity
    
    
    2,493,809
    
    
    2,582,970








**Number
      of Shares**
    
    **Optional****Outstanding**
    
    **Redemption
      Price****2004**
    
    **2003**
    
    **Per
      Share**
    
    **Aggregate****PREFERRED
      STOCK NOT SUBJECT TO**
      **MANDATORY
      REDEMPTION (Note 9(B)):**Cumulative,
      $100 par value-Authorized
      6,000,000 shares3.90%
    
    
    152,510
    
    
    152,510
    
    $
    103.63
    
    $
    15,804
    
    
    15,251
    
    
    15,2514.40%
    
    
    176,280
    
    
    176,280
    
    
    108.00
    
    
    19,038
    
    
    17,628
    
    
    17,6284.44%
    
    
    136,560
    
    
    136,560
    
    
    103.50
    
    
    14,134
    
    
    13,656
    
    
    13,6564.56%
    
    
    144,300
    
    
    144,300
    
    
    103.38
    
    
    14,917
    
    
    14,430
    
    
    14,430Total
    
    
    609,650
    
    
    609,650
    
    
    
    
    $
    63,893
    
    
    60,965
    
    
    60,965**PREFERRED
      STOCK OF CONSOLIDATED**
      **SUBSIDIARY
      NOT SUBJECT TO MANDATORY**
      **REDEMPTION
      (Note 9(B)):****Pennsylvania
      Power Company-**Cumulative,
      $100 par value-Authorized
      1,200,000 shares4.24%
    
    
    40,000
    
    
    40,000
    
    $
    103.13
    
    $
    4,125
    
    
    4,000
    
    
    4,0004.25%
    
    
    41,049
    
    
    41,049
    
    
    105.00
    
    
    4,310
    
    
    4,105
    
    
    4,1054.64%
    
    
    60,000
    
    
    60,000
    
    
    102.98
    
    
    6,179
    
    
    6,000
    
    
    6,0007.75%
    
    
    250,000
    
    
    250,000
    
    
    100.00
    
    
    25,000
    
    
    25,000
    
    
    25,000Total
    
    
    391,049
    
    
    391,049
    
    
    
    
    $
    39,614
    
    
    39,105
    
    
    39,105








19





**OHIO EDISON
COMPANY**





**CONSOLIDATED
STATEMENTS OF CAPITALIZATION (Cont'd)**





**As
      of December 31,**
    
    **2004**
    
    **2003**
    
    
    
    **2004**
    
    **2003**
    
    **2004**
    
    **2003*****(In
      thousands)***LONG-TERM
      DEBT AND OTHERLONG-TERM
      OBLIGATIONS (Note 9(C)):**First
      mortgage bonds:**Ohio
      Edison Company-
    
    
    
    
    
    Pennsylvania
      Power Company-6.875% due
      2005
    
    
    80,000
    
    
    80,000
    
    
    9.740% due
      2005-2019
    
    
    14,643
    
    
    15,6176.375%
      due 2004
    
    
    --
    
    
    20,5006.625%
      due 2004
    
    
    --
    
    
    14,0008,500%
      due 2022
    
    
    --
    
    
    27,2507.625%
      due 2023
    
    
    6,500
    
    
    6,500Total
      first mortgage bonds
    
    
    80,000
    
    
    80,000
    
    
    
    
    
    21,143
    
    
    83,867
    
    
    101,143
    
    
    163,867**Secured
      notes:****Ohio
      Edison Company**-
    
    
    
    
    
    
    
    **Pennsylvania
      Power Company-**7.680% due 2005
    
    
    51,461
    
    
    109,081
    
    
    5.400% due 2013
    
    
    1,000
    
    
    1,000*  1.700%
      due 2015
    
    
    19,000
    
    
    19,000
    
    
    5.400% due 2017
    
    
    10,600
    
    
    10,6006.750% due 2015
    
    
    40,000
    
    
    40,000
    
    
    *  1.700%
      due 2017
    
    
    17,925
    
    
    17,925*   3.250%
      due 2015
    
    
    50,000
    
    
    50,000
    
    
    5.900% due 2018
    
    
    16,800
    
    
    16,800*   1.800%
      due 2016
    
    
    47,725
    
    
    --
    
    
    *  1.700%
      due 2021
    
    
    14,482
    
    
    14,4827.050% due 2020
    
    
    60,000
    
    
    60,000
    
    
    6.150% due 2023
    
    
    12,700
    
    
    12,700*   1.700%
      due 2021
    
    
    443
    
    
    443
    
    
    *  2.000%
      due 2027
    
    
    10,300
    
    
    10,3005.375% due 2028
    
    
    13,522
    
    
    13,522
    
    
    5.375% due 2028
    
    
    1,734
    
    
    1,7345.625% due 2029
    
    
    50,000
    
    
    50,000
    
    
    5.450% due 2028
    
    
    6,950
    
    
    6,9505.950% due 2029
    
    
    56,212
    
    
    56,212
    
    
    6.000% due 2028
    
    
    14,250
    
    
    14,250*   1.710%
      due 2030
    
    
    60,400
    
    
    60,400
    
    
    5.950% due 2029
    
    
    238
    
    
    238*   1.700%
      due 2031
    
    
    69,500
    
    
    69,500
    
    
    1.800% due 2033
    
    
    5,200
    
    
    --*   1.800%
      due 2033
    
    
    44,800
    
    
    44,8001.750% due 2033
    
    
    12,300
    
    
    12,3005.450% due 2033
    
    
    14,800
    
    
    14,800*   2.250%
      due 2033
    
    
    50,000
    
    
    50,0001.800% due 2033
    
    
    108,000
    
    
    --Limited
      Partnerships-7.35%
      weighted average
      interest rate due
      2005-201017,272
    
    
    21,432Total secured
      notes
    
    
    765,435
    
    
    671,490
    
    
    
    
    
    112,179
    
    
    106,979
    
    
    877,614
    
    
    778,469**Unsecured
      notes:****Ohio
      Edison Company-**
    
    
    
    
    
    
    
    **Pennsylvania
      Power Company-*** 
        2.238% due 2005
    
    
    --
    
    
    40,000
    
    
    *  3.375%
      due 2029
    
    
    14,500
    
    
    14,5004.000% due 2008
    
    
    175,000
    
    
    175,000
    
    
    *  5.900%
      due 2033
    
    
    --
    
    
    5,200* 
        1.980% due 2014
    
    
    50,000
    
    
    50,0005.450% due 2015
    
    
    150,000
    
    
    150,000* 
        5.800% due 2016
    
    
    --
    
    
    47,725* 
        2.230% due 2018
    
    
    33,000
    
    
    33,000* 
        2.150% due 2018
    
    
    23,000
    
    
    23,000* 
        2.150% due 2023
    
    
    50,000
    
    
    50,000* 
        4.650% due 2033
    
    
    --
    
    
    108,000* 
        3.350% due 2033
    
    
    30,000
    
    
    --Total
      unsecured notes
    
    
    511,000
    
    
    676,725
    
    
    
    
    
    14,500
    
    
    19,700
    
    
    525,500
    
    
    696,425Preferred
      stock subject to mandatory redemption
    
    
    
    
    
    
    
    
    
    
    
    
    
    12,750
    
    
    13,500Capital lease
      obligations (Note 6)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    5,223
    
    
    6,829Net
      unamortized discount on debt
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (9,053
    )
    
    (12,712
    )Long-term debt
      due within one year
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (398,263
    )
    
    (466,589
    )Total
      long-term debt and long-term obligations
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,114,914
    
    
    1,179,789**TOTAL
      CAPITALIZATION**
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    $
    3,708,793
    
    $
    3,862,829


*  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.





20





**OHIO EDISON
COMPANY**





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











Comprehensive
      **Income**
    
    ****
      
      Number
      of
      Shares
    
    **Carrying**
      **Value**
    
    **Accumulated**
      **Other**
      **Comprehensive**
      **Income
      (Loss)**
    
    **Retained**
      **Earnings*****(Dollars
      in thousands)***Balance,
      January 1, 2002
    
    
    
    
    
    100
    
    $
    2,098,729
    
    $
    --
    
    $
    572,272Net
      income
    
    $
    356,159
    
    
    
    
    
    
    
    
    
    
    
    356,159Minimum
      liability for unfunded retirement
      benefits, net
      of $(45,525,000) of income taxes
    
    
    (64,585
    )
    
    
    
    
    
    
    
    (64,585
    )Unrealized
      gain on investments, net of
      $3,582,000 of
      income taxes
    
    
    5,090
    
    
    
    
    
    
    
    
    5,090Comprehensive
      income
    
    $
    296,664Cash
      dividends on preferred stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (6,510
    )Cash
      dividends on common stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (121,900
    )Balance,
      December 31, 2002
    
    
    
    
    
    100
    
    
    2,098,729
    
    
    (59,495
    )
    
    800,021Net
      income
    
    $
    324,645
    
    
    
    
    
    
    
    
    
    
    
    324,645Minimum
      liability for unfunded retirement
      benefits, net
      of $2,014,000 of income taxes
    
    
    2,674
    
    
    
    
    
    
    
    
    2,674Unrealized
      gain on investments, net of
      $12,337,000 of
      income taxes
    
    
    18,128
    
    
    
    
    
    
    
    
    18,128Comprehensive
      income
    
    $
    345,447Cash dividends
      on preferred stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (2,732
    )Cash dividends
      on common stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (599,000
    )Balance,
      December 31, 2003
    
    
    
    
    
    100
    
    
    2,098,729
    
    
    (38,693
    )
    
    522,934Net
      income
    
    $
    342,766
    
    
    
    
    
    
    
    
    
    
    
    342,766Minimum
      liability for unfunded retirement
      benefits, net
      of $(5,516,000) of income taxes
    
    
    (7,552
    )
    
    
    
    
    
    
    
    (7,552
    )Unrealized
      loss on investments, net of
      $(533,000) of
      income taxes
    
    
    (873
    )
    
    
    
    
    
    
    
    (873
    )Comprehensive
      income
    
    $
    334,341Cash dividends
      on preferred stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (2,502
    )Cash dividends
      on common stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (421,000
    )Balance,
      December 31, 2004
    
    
    
    
    
    100
    
    $
    2,098,729
    
    $
    (47,118
    )
    $
    442,198











**CONSOLIDATED
STATEMENTS OF PREFERRED STOCK**








**Not
      Subject to**
      **Mandatory
      Redemption**
    
    ****
      **Subject
      to**
      **Mandatory
      Redemption**********
    
    **Number**
      **of
      Shares**
    
    **Par**
      **Value**
    
    **Number**
      **of
      Shares**
    
    **Par**
      **Value**********
    
    ***(Dollars
      in thousands)***Balance,
      January 1, 2002
    
    5,000,699
    
    $200,070
    
    4,950,000
    
    $135,000Redemptions
      -7.75%Series
    
    
    (4,000,000
    )
    
    (100,000
    )9.00%Series
    
    
    
    
    
    
    
    
    (4,800,000
    )
    
    (120,000
    )7.625%Series
    
    
    
    
    
    
    
    
    (7,500
    )
    
    (750
    )Balance,
      December 31, 2002
    
    
    1,000,699
    
    
    100,070
    
    
    142,500
    
    
    14,250Redemptions
      -7.625%Series
    
    
    
    
    
    
    
    
    (7,500
    )
    
    (750
    )Balance,
      December 31, 2003
    
    
    1,000,699
    
    
    100,070
    
    
    135,000
    
    
    13,500*Redemptions
      -7.625%
      Series
    
    
    
    
    
    
    
    
    (7,500
    )
    
    (750
    )Balance,
      December 31, 2004
    
    
    1,000,699
    
    $
    100,070
    
    
    127,500
    
    $
    12,750*


* 
  The December 31, 2003 and 2004 balances for Preferred stock subject
to mandatory redemption are classified as debt under SFAS 150.





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





21





**OHIO 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
    
    $
    342,766
    
    $
    324,645
    
    $
    356,159Adjustments
      to reconcile net income to net
      cash from
      operating activities:Provision for
      depreciation
    
    
    122,413
    
    
    117,895
    
    
    142,083Amortization
      of regulatory assets
    
    
    411,326
    
    
    393,409
    
    
    335,523Deferral of
      new regulatory assets
    
    
    (100,633
    )
    
    (73,183
    )
    
    (92,086
    )Nuclear fuel
      and lease amortization
    
    
    42,811
    
    
    39,317
    
    
    47,597Deferred
      lease costs
    
    
    (5,170
    )
    
    (4,183
    )
    
    1,360Deferred
      income taxes and investment tax credits, net
    
    
    (44,469
    )
    
    (88,288
    )
    
    (75,719
    )Accrued
      retirement benefit obligations
    
    
    31,289
    
    
    47,524
    
    
    18,069Accrued
      compensation, net
    
    
    4,551
    
    
    (14,459
    )
    
    9,720Cumulative
      effect of accounting change
    
    
    --
    
    
    (54,109
    )
    
    --Pension trust
      contribution
    
    
    (72,763
    )
    
    --
    
    
    --Decrease
      (increase) in operating assets:Receivables
    
    
    209,130
    
    
    170,492
    
    
    (41,584
    )Materials and
      supplies
    
    
    (10,259
    )
    
    (2,038
    )
    
    (9,930
    )Prepayments
      and other current assets
    
    
    1,286
    
    
    (2,586
    )
    
    38,737Increase
      (decrease) in operating liabilities:Accounts
      payable
    
    
    (80,738
    )
    
    132,983
    
    
    182,229Accrued
      taxes
    
    
    (406,945
    )
    
    94,281
    
    
    208,945Accrued
      interest
    
    
    (6,722
    )
    
    (9,495
    )
    
    (4,844
    )Other
    
    
    (18,066
    )
    
    (12,221
    )
    
    (43,206
    )Net cash
      provided from operating activities
    
    
    419,807
    
    
    1,059,984
    
    
    1,073,053**CASH
      FLOWS FROM FINANCING ACTIVITIES:**New
      Financing-Long-term
      debt
    
    
    30,000
    
    
    365,000
    
    
    14,500Short-term
      borrowings, net
    
    
    --
    
    
    --
    
    
    161,836Redemptions
      and Repayments-Preferred
      stock
    
    
    (750
    )
    
    (750
    )
    
    (220,750
    )Long-term
      debt
    
    
    (170,997
    )
    
    (519,506
    )
    
    (425,742
    )Short-term
      borrowings, net
    
    
    (4,015
    )
    
    (224,788
    )
    
    --Dividend
      Payments-Common
      stock
    
    
    (421,000
    )
    
    (599,000
    )
    
    (121,900
    )Preferred
      stock
    
    
    (2,502
    )
    
    (2,732
    )
    
    (6,510
    )Net cash used
      for financing activities
    
    
    (569,264
    )
    
    (981,776
    )
    
    (598,566
    )**CASH
      FLOWS FROM INVESTING ACTIVITIES:**Property
      additions
    
    
    (235,022
    )
    
    (189,019
    )
    
    (148,967
    )Contributions
      to nuclear decommissioning trusts
    
    
    (31,540
    )
    
    (31,540
    )
    
    (31,540
    )Loan
      repayments from (loans to) associated companies, net
    
    
    128,054
    
    
    66,401
    
    
    (327,876
    )Proceeds from
      certificates of deposits
    
    
    277,763
    
    
    --
    
    
    --Other
    
    
    9,549
    
    
    57,321
    
    
    49,820Net cash
      provided from (used for) investing activities
    
    
    148,804
    
    
    (96,837
    )
    
    (458,563
    )Net increase
      (decrease) in cash and cash equivalents
    
    
    (653
    )
    
    (18,629
    )
    
    15,924Cash and cash
      equivalents at beginning of year
    
    
    1,883
    
    
    20,512
    
    
    4,588Cash and cash
      equivalents at end of year
    
    $
    1,230
    
    $
    1,883
    
    $
    20,512**SUPPLEMENTAL
      CASH FLOWS INFORMATION:**Cash Paid
      During the Year-Interest (net
      of amounts capitalized)
    
    $
    65,765
    
    $
    103,632
    
    $
    118,535Income
      taxes
    
    $
    419,123
    
    $
    250,564
    
    $
    126,558







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








22





**OHIO EDISON
COMPANY**





**CONSOLIDATED
STATEMENTS OF TAXES**





**For
      the Years Ended December 31,**
    
    **2004**
    
    **2003**
    
    **2002*****(In
      thousands)*****GENERAL
      TAXES:**Ohio
      kilowatt-hour excise*
    
    $
    91,811
    
    $
    91,296
    
    $
    85,762State gross
      receipts*
    
    
    19,234
    
    
    18,028
    
    
    18,516Real and
      personal property
    
    
    58,000
    
    
    51,074
    
    
    65,709Social
      security and unemployment
    
    
    7,048
    
    
    6,992
    
    
    5,438Other
    
    
    4,430
    
    
    2,688
    
    
    1,596Total general
      taxes
    
    $
    180,523
    
    $
    170,078
    
    $
    177,021**PROVISION
      FOR INCOME TAXES:**Currently
      payable-Federal
    
    $
    246,865
    
    $
    270,345
    
    $
    280,587State
    
    
    75,907
    
    
    81,505
    
    
    55,796322,772
    
    
    351,850
    
    
    336,383Deferred,
      net-Federal
    
    
    (23,668
    )
    
    (57,503
    )
    
    (44,552
    )State
    
    
    (5,512
    )
    
    (16,038
    )
    
    (22,184
    )(29,180
    )
    
    (73,541
    )
    
    (66,736
    )Investment
      tax credit amortization
    
    
    (15,289
    )
    
    (14,747
    )
    
    (13,732
    )Total
      provision for income taxes
    
    $
    278,303
    
    $
    263,562
    
    $
    255,915**INCOME
      STATEMENT CLASSIFICATION**
      **OF
      PROVISION FOR INCOME TAXES:**Operating
      income
    
    $
    257,114
    
    $
    216,979
    
    $
    229,001Other
      income
    
    
    21,189
    
    
    24,194
    
    
    26,914Cumulative
      effect of accounting change
    
    
    --
    
    
    22,389
    
    
    --Total
      provision for income taxes
    
    $
    278,303
    
    $
    263,562
    
    $
    255,915**RECONCILIATION
      OF FEDERAL INCOME TAX EXPENSE AT**
      **STATUTORY
      RATE TO TOTAL PROVISION FOR INCOME TAXES:**Book income
      before provision for income taxes
    
    $
    621,069
    
    $
    588,207
    
    $
    612,074Federal
      income tax expense at statutory rate
    
    $
    217,374
    
    $
    205,872
    
    $
    214,225Increases
      (reductions) in taxes resulting from-Amortization
      of investment tax credits
    
    
    (15,289
    )
    
    (14,747
    )
    
    (13,732
    )State income
      taxes, net of federal income tax benefit
    
    
    45,757
    
    
    42,554
    
    
    21,848Amortization
      of tax regulatory assets
    
    
    34,019
    
    
    33,219
    
    
    30,659Other,
      net
    
    
    (3,558
    )
    
    (3,336
    )
    
    2,915Total
      provision for income taxes
    
    $
    278,303
    
    $
    263,562
    
    $
    255,915**ACCUMULATED
      DEFERRED INCOME TAXES AT DECEMBER 31:**Property
      basis differences
    
    $
    451,269
    
    $
    406,783
    
    $
    397,930Allowance for
      equity funds used during construction
    
    
    27,730
    
    
    30,493
    
    
    34,407Regulatory
      transition charge
    
    
    154,015
    
    
    345,723
    
    
    527,502Customer
      receivables for future income taxes
    
    
    39,266
    
    
    44,382
    
    
    49,486Deferred sale
      and leaseback costs
    
    
    (63,432
    )
    
    (67,837
    )
    
    (71,830
    )Unamortized
      investment tax credits
    
    
    (23,510
    )
    
    (29,031
    )
    
    (33,421
    )Deferred gain
      for asset sale to affiliated company
    
    
    51,716
    
    
    53,010
    
    
    70,812Other
      comprehensive income
    
    
    (33,268
    )
    
    (27,219
    )
    
    (41,570
    )Retirement
      benefits
    
    
    (6,202
    )
    
    (29,676
    )
    
    20,969Shopping
      credit incentive deferral
    
    
    94,002
    
    
    57,731
    
    
    32,476All
      other
    
    
    74,690
    
    
    83,332
    
    
    30,868Net deferred
      income tax liability
    
    $
    766,276
    
    $
    867,691
    
    $
    1,017,629








*  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.





23





**NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS**





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


The consolidated
financial statements include OE (Company) and its wholly owned subsidiaries.
Penn is the Company's principal operating subsidiary. 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, TE, ATSI, JCP&L, Met-Ed and
Penelec.
 
 The Company and
Penn (Companies) follow GAAP and comply with the regulations, orders, policies
and practices prescribed by the SEC, PUCO, the PPUC and the FERC. The
preparation of financial statements in conformity with GAAP requires management
to make periodic estimates and assumptions that affect the reported amounts of
assets, liabilities, revenues and expenses and the disclosure of contingent
assets and liabilities. Actual results could differ from these estimates.
C ertain 2003
revenues and expenses have been reclassified and presented on a net basis to
conform with the current year presentation.
 
 The Company
consolidates all majority-owned subsidiaries over which the Company exercises
control and, when applicable, entities for which the Company has a controlling
financial interest. Intercompany transactions and balances are eliminated in
consolidation. Investments in nonconsolidated affiliates (20-50 percent owned
companies, joint ventures and partnerships) over which the Company has the
ability to exercise significant influence, but not control, are accounted for on
the equity basis.
 
 Unless otherwise
indicated, defined terms used herein have the meanings set forth in the
accompanying Glossary of Terms.


**2.**
    **SUMMARY
      OF SIGNIFICANT ACCOUNTING POLICIES:**





**(A)**
    **ACCOUNTING
      FOR THE EFFECTS OF REGULATION-**





The Companies
account for the effects of regulation through the application of SFAS 71 when
their 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 Companies
recognize, as regulatory assets, costs which the FERC, PUCO and PPUC have
authorized for recovery from customers in future periods or for which
authorization is probable. Without the probability of such authorization, costs
currently recorded as regulatory assets would have been charged to income as
incurred. All regulatory assets are expected to be recovered from customers
under the Companies' respective transition and rate restructuring plans. Based
on those plans, the Companies continue to bill and collect cost-based rates for
their transmission and distribution services, which remain regulated;
accordingly, it is appropriate that the Companies continue the application of
SFAS 71 to those operations.








24





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








**2004***
    
    **2003*****(In
      millions)***Regulatory
      transition costs
    
    $
    835
    
    $
    1,331Customer
      shopping incentives
    
    
    228
    
    
    140Customer
      receivables for future income taxes
    
    
    99
    
    
    115Loss on
      reacquired debt
    
    
    23
    
    
    29Employee
      postretirement benefit costs
    
    
    2
    
    
    6Nuclear
      decommissioning costs
    
    
    --
    
    
    (72
    )Asset removal
      costs
    
    
    (72
    )
    
    (72
    )Other
    
    
    1
    
    
    1Total
    
    $
    1,116
    
    $
    1,478





*
    Changes in
      Penn's net regulatory asset components in 2004 resulted in net regulatory
      liabilities of approximately $18 million included in Other Noncurrent
      Liabilities on the Consolidated Balance Sheet as of December 31,
      2004.








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 $228 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 - Ohio) using the effective
interest method. Under the Rate Stabilization Plan, total transition cost
amortization is expected to approximate the following for 2005 through 2007.





***(In
      millions)***2005
    
    $
    4672006
    
    
    1932007
    
    
    93





The decrease in
amortization in 2006 results from the termination of generation-related
transition cost recovery under the Ohio transition plan.





*Accounting for
Generation Operations-*





The application of
SFAS 71 was discontinued prior to 2001 with respect to the Companies' generation
operations. The SEC's interpretive guidance 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 and EITF 97-4, $1.2
billion of impaired plant investments were recognized by the Company as
regulatory assets recoverable as transition costs through future regulatory cash
flows and $227 million were recognized for Penn related to its 1998 impairment
of its nuclear generating unit investments to be recovered through a CTC over a
seven-year transition period.





Net assets included
in utility plant relating to the operations for which the application of SFAS 71
was discontinued, compared to the respective company's total assets as of
December 31, 2004 were $1.059 billion and $5.8 billion, respectively, for
the Company and $263 million and $921 million, respectively, for
Penn.





**(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.





25





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





The Companies'
principal business is providing electric service to customers in Ohio and
Pennsylvania. The Companies' 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 Companies accrue the
estimated unbilled amount receivable as revenue and reverse the related prior
period estimate.





Receivables from
customers include sales to residential, commercial and industrial customers and
sales to wholesale customers. There was no material concentration of receivables
as of December 31, 2004 or 2003, with respect to any particular segment of
the Companies' customers. Total customer receivables were $274 million (billed -
$172 million and unbilled - $102 million) and $281 million (billed - $165
million and unbilled - $116 million) as of December 31, 2004 and 2003,
respectively.





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





Utility plant
reflects original cost of construction (except for the Companies' 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
Companies' accounting policy for planned major maintenance projects is to
recognize liabilities as they are incurred.





The Companies
provide for depreciation on a straight-line basis at various rates over the
estimated lives of property included in plant in service. The annual composite
rate for the Company's electric plant was approximately 2.3% in 2004, 2.2% in
2003 and 2.4% in 2002. The annual composite rate for Penn's electric plant was
approximately 2.2% in 2004 and 2003 and 2.3% in 2002.





*Jointly - Owned
Generating Stations* -





The Companies,
together with CEI and TE, 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 Companies’ portions of operating expenses associated with jointly
- owned facilities are 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:








**Companies’****Utility**
    
    **Accumulated**
    
    **Construction**
    
    **Ownership/****Plant**
    
    **Provision
      for**
    
    **Work
      in**
    
    **Leasehold****Generating
      Units**
    
    **in
      Service**
    
    **Depreciation**
    
    **Progress**
    
    **Interest*****(In
      millions)***W. H. Sammis
      Unit 7
    
    $
    335
    
    $
    173
    
    $
    --
    
    
    68.80
    %Bruce
      Mansfield Units 1, 2 and 3
    
    
    989
    
    
    549
    
    
    --
    
    
    67.18
    %Beaver Valley
      Units 1 and 2
    
    
    230
    
    
    40
    
    
    160
    
    
    77.81
    %Perry
    
    
    364
    
    
    357
    
    
    9
    
    
    35.24
    %Total
    
    $
    1,918
    
    $
    1,119
    
    $
    169





*Asset
Retirement Obligations-*





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





*Nuclear
Fuel-*





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








26





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





*Long-Lived
Assets-*





The Companies
evaluate the carrying value of their long-lived assets when events or
circumstances indicate that the carrying amount may not be recoverable. In
accordance with SFAS 144, the carrying amount of a long-lived asset is not
recoverable if it exceeds the sum of the undiscounted cash flows expected to
result from the use and eventual disposition of the asset. If an impairment
exists, a loss is recognized for the amount by which the carrying value of the
long-lived asset exceeds its estimated fair value. Fair value is estimated by
using available market valuations or the long-lived asset's expected future net
discounted cash flows. The calculation of expected cash flows is based on
estimates and assumptions about future events.





*Investments-*





The Companies
periodically evaluate for impairment investments that include available-for-sale
securities held by their nuclear decommissioning trusts. In accordance with SFAS
115, securities classified as available-for-sale are evaluated to determine
whether a decline in fair value below the cost basis is other than temporary. If
the decline in fair value is determined to be other than temporary, the cost
basis of the security is written down to fair value. The Companies consider,
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 Companies' investments are disclosed in Note
5.





**(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, AOCL consisted of a minimum liability for unfunded
retirement benefits of $69 million and unrealized gains on investments in
securities available for sale of $22 million. As of December 31, 2003,
accumulated other comprehensive loss consisted of a minimum liability for
unfunded retirement benefits of $62 million and unrealized gains on investments
in securities available for sale of $23 million.





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





Upon adoption of
SFAS 143 in the first quarter of 2003, OE recorded an after-tax credit to net
income of $32 million. The cumulative adjustment for unrecognized depreciation,
accretion offset by the reduction in the existing decommissioning liabilities
and ceasing the accounting practice of depreciating non-regulated generation
assets using a cost of removal component was a $54 million increase to income,
or $32 million net of income taxes.





**(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 Companies are included
in FirstEnergy's consolidated federal income tax return. The consolidated tax
liability is allocated on a "stand-alone" company basis, with the Companies
recognizing any tax losses or credits they contribute 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 Companies, CEI and TE. As a result, the Companies
entered into power supply agreements (PSA) whereby FES purchases all of the
Companies' nuclear generation and the Companies purchase their power from FES to
meet their "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.


The primary
affiliated companies transactions are as follows:





27








**2004**
    
    **2003**
    
    **2002*****(In
      millions)*****Operating
      Revenues:**PSA revenues
      from FES
    
    $
    416
    
    $
    384
    
    $
    329Generating
      units rent from FES
    
    
    178
    
    
    178
    
    
    178Ground lease
      with ATSI
    
    
    12
    
    
    12
    
    
    12**Operating
      Expenses:**Purchased
      power under PSA
    
    
    970
    
    
    902
    
    
    912Transmission
      expense
    
    
    --
    
    
    65
    
    
    85FESC support
      services
    
    
    91
    
    
    116
    
    
    141**Other
      Income:**Interest
      income from ATSI
    
    
    16
    
    
    16
    
    
    16Interest
      income from FES
    
    
    9
    
    
    12
    
    
    12








FirstEnergy does
not bill directly or allocate any of its costs to any subsidiary company. Costs
are allocated to the Companies 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 certain amounts due from
FirstEnergy related to the formation of the holding company ($61 million) and
receivables from affiliates for OPEB obligations ($17 million).





**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 (Companies' share was $73 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 (Companies' share was $44
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
    )Companies'
      share of net amount recognized
    
    
    
    
    $
    118
    
    $
    53
    
    $
    (272
    )
    $
    (249
    )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
    %








29








**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





**Components
      of Net Periodic Benefit Costs**
    
    **Pension
      Benefits**
    
    **Other
      Benefits****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
    
    $
    114Companies'
      share of net periodic cost
    
    $
    7
    
    $
    24
    
    $
    3
    
    $
    28
    
    $
    43
    
    $
    15**Weighted-Average
      Assumptions Used****to
      Determine Net Periodic Benefit Cost**
    
    **Pension
      Benefits**
    **Other
      Benefits****for
      Years Ended December 31**
    
    
    **2004**
    
    
    **2003**
    
    
    **2002**
    
    
    **2004**
    
    
    **2003**
    
    
    **2002**Discount
      rate
    
    
    6.25
    %
    
    6.75
    %
    
    7.25
    %
    
    6.25
    %
    
    6.75
    %
    
    7.25
    %Expected
      long-term return on plan assets
    
    
    9.00
    %
    
    9.00
    %
    
    10.25
    %
    
    9.00
    %
    
    9.00
    %
    
    10.25
    %Rate of
      compensation increase
    
    
    3.50
    %
    
    3.50
    %
    
    4.00
    %








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





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








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








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





30








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





Pursuant to FSP
106-1 issued January 12, 2004, FirstEnergy began accounting for the effects
of the Medicare Act effective January 1, 2004 because of a plan amendment
during the quarter, which required remeasurement of the plan's obligations.
T he
plan amendment, which increases cost-sharing by employees and retirees effective
January 1, 2005, reduced the Companies’ postretirement benefit costs by $14
million during 2004.





Consistent with the
guidance in FSP 106-2 issued on May 19, 2004, FirstEnergy recognized a
reduction of $318 million in the accumulated postretirement benefit obligation
as a result of the federal subsidy provided under the Medicare Act related to
benefits for past service. This reduction was accounted for as an actuarial gain
in 2004 pursuant to FSP 106-2.The subsidy reduced the Companies’ net periodic
postretirement benefit costs by $11 million during 2004.





As a result of
their voluntary contribution and the increased market value of pension plan
assets, the Companies reduced their accrued benefit cost as of December 31,
2004 by $48 million. As prescribed by SFAS 87, the Companies increased their
additional minimum liability by $18 million, recording an increase in an
intangible asset of $5 million and debiting OCI by $13 million. The balance in
AOCL of $69 million (net of $49 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.**
    **ESOP:**





An ESOP Trust funds
most of the matching contribution for FirstEnergy's 401(k) savings plan. All
full-time employees eligible for participation in the 401(k) savings plan are
covered by the ESOP. The ESOP borrowed $200 million from OE and acquired
10,654,114 shares of OE's common stock (subsequently converted to FirstEnergy
common stock) through market purchases. Dividends on ESOP shares are used to
service the debt. Shares are released from the ESOP on a pro rata basis as debt
service payments are made. As of December 31, 2004, the Company had an
approximately $61 million receivable from FirstEnergy representing reductions to
the outstanding loan balance from the ESOP Trust that were paid to FirstEnergy
since 1998 that were intended to be remitted to the Company; that receivable
will be paid in December 2005.





**5.**
    **FAIR
      VALUE OF FINANCIAL INSTRUMENTS:**





*Long-term Debt
and Other Long-term Obligations-*





All borrowings with
initial maturities of less than one year are defined as financial instruments
under GAAP and are reported on the Consolidated Balance Sheets at cost, which
approximates their fair market value. The following table provides the
approximate fair value and related carrying amounts of long-term debt and other
long-term obligations as of December 31:





**2004**
    
    **2003****Carrying**
    
    **Fair**
    
    **Carrying**
    
    **Fair****Value**
    
    **Value**
    
    **Value**
    
    **Value*****(In
      millions)***Long-term
      debt
    
    $
    1,504
    
    $
    1,528
    
    $
    1,639
    
    $
    1,677Preferred
      stock subject to mandatory
      redemption
    
    
    13
    
    
    12
    
    
    14
    
    
    14$
    1,517
    
    $
    1,540
    
    $
    1,653
    
    $
    1,691








31


The fair values of
long-term debt and other long-term obligations reflect the present value of the
cash outflows relating to those securities based on the current call price, the
yield to maturity or the yield to call, as deemed appropriate at the end of each
respective year. The yields assumed were based on securities with similar
characteristics offered by a corporation with credit ratings similar to the
Companies' 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
    
    $
    137
    
    $
    137
    
    $
    126
    
    $
    126-Corporate
      debt securities(2)
    
    
    609
    
    
    708
    
    
    1,063
    
    
    1,126-Mortgage-backed
      securities
    
    
    1
    
    
    1
    
    
    --
    
    
    --747
    
    
    846
    
    
    1,189
    
    
    1,252Equity
      securities(1)
    
    
    289
    
    
    289
    
    
    260
    
    
    260$
    1,036
    
    $
    1,135
    
    $
    1,449
    
    $
    1,512




(1)  Includes nuclear
decommissioning trust investments.


(2)  Includes
investments in lease obligation bonds (see Note 6).








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





Investments other
than cash and cash equivalents include held-to-maturity securities and
available-for-sale securities. Decommissioning trust investments are classified
as available-for-sale. The Companies have 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
    
    $
    186
    
    $
    3
    
    $
    1
    
    $
    188
    
    $
    164
    
    $
    4
    
    $
    --
    
    $
    168Equity
      securities
    
    
    205
    
    
    49
    
    
    6
    
    
    248
    
    
    165
    
    
    52
    
    
    9
    
    
    208$
    391
    
    $
    52
    
    $
    7
    
    $
    436
    
    $
    329
    
    $
    56
    
    $
    9
    
    $
    376








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
    
    $
    154
    
    $
    189
    
    $
    125Gross
      realized gains
    
    
    25
    
    
    10
    
    
    4Gross
      realized losses
    
    
    7
    
    
    5
    
    
    8Interest and
      dividend income
    
    
    13
    
    
    10
    
    
    9








32





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**
      **Value**
    
    **Unrealized**
      **Losses**
    
    **Fair**
      **Value**
    
    **Unrealized**
      **Losses**
    
    **Fair**
      **Value**
    
    **Unrealized**
      **Losses*****(In
      millions)***Debt
      securities
    
    $
    64
    
    $
    1
    
    $
    5
    
    $
    --
    
    $
    69
    
    $
    1Equity
      securities
    
    
    12
    
    
    2
    
    
    28
    
    
    4
    
    
    40
    
    
    6$
    76
    
    $
    3
    
    $
    33
    
    $
    4
    
    $
    109
    
    $
    7





The Companies
periodically evaluate the securities held by their nuclear decommissioning
trusts for other-than-temporary impairment. The Companies consider 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. Penn's decommissioning trusts are subject to regulatory accounting in
accordance with SFAS 71. Net unrealized gains and losses are recorded as
regulatory liabilities or assets since the difference between investments held
in trust and the decommissioning liabilities are recovered from or refunded to
customers.





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





**6.**
    **LEASES:**





The Companies lease
certain generating facilities, office space and other property and equipment
under cancelable and noncancelable leases.





The Company sold
portions of its ownership interest in Perry Unit 1 and Beaver Valley Unit 2 and
entered into operating leases on the portions sold for basic lease terms of
approximately 29 years. During the terms of the leases, the Company continues to
be responsible, to the extent of its individual combined ownership and leasehold
interests, for costs associated with the units including construction
expenditures, operation and maintenance expenses, insurance, nuclear fuel,
property taxes and decommissioning. The Company has the right, at the end of the
respective basic lease terms, to renew the leases for up to two years. The
Company also has 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. The basic rental payments are adjusted when applicable
federal tax law changes.





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
    
    $
    94.1
    
    $
    96.4
    
    $
    100.9Other
    
    
    47.1
    
    
    41.2
    
    
    34.6Capital
      leasesInterest
      element
    
    
    1.0
    
    
    1.7
    
    
    1.6Other
    
    
    1.6
    
    
    1.4
    
    
    1.3Total
      rentals
    
    $
    143.8
    
    $
    140.7
    
    $
    138.4








33





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








**Operating
      Leases****PNBV****Capital**
    
    **Lease**
    
    **Capital****Leases**
    
    **Payments**
    
    **Trusts**
    
    **Net*****(In
      millions)***2005
    
    $
    4.3
    
    $
    138.8
    
    $
    56.6
    
    $
    82.22006
    
    
    4.3
    
    
    139.9
    
    
    59.5
    
    
    80.42007
    
    
    0.3
    
    
    139.3
    
    
    59.9
    
    
    79.42008
    
    
    0.3
    
    
    139.6
    
    
    34.9
    
    
    104.72009
    
    
    0.3
    
    
    140.1
    
    
    42.1
    
    
    98.0Years
      thereafter
    
    
    1.3
    
    
    992.9
    
    
    279.4
    
    
    713.5Total minimum
      lease payments
    
    
    10.8
    
    $
    1,690.6
    
    $
    532.4
    
    $
    1,158.2Executory
      costs
    
    
    3.7Net minimum
      lease payments
    
    
    7.1Interest
      portion
    
    
    1.8Present value
      of net minimum
      lease
      payments
    
    
    5.3Less current
      portion
    
    
    1.9Noncurrent
      portion
    
    $
    3.4





The Company
invested in the PNBV Capital Trust, which was established to purchase a portion
of the lease obligation bonds issued on behalf of lessors in the Company’s Perry
Unit 1 and Beaver Valley Unit 2 sale and leaseback transactions. The
PNBV capital trust arrangement effectively reduces lease costs related to those
transactions. OE has LOCs of $294 million and $154 million in connection with
the sale and leaseback of Beaver Valley Unit 2 and Perry Unit 1,
respectively.





**7.**
    **VARIABLE
      INTEREST ENTITIES:**
      ****


FIN 46R addresses
the consolidation of VIEs, including special-purpose entities, that are not
controlled through voting interests or in which the equity investors do not bear
the residual economic risks and rewards. FirstEnergy adopted FIN 46R for
special-purpose entities as of December 31, 2003 and for all other entities in
the first quarter of 2004. The first step under FIN 46R is to determine whether
an entity is within the scope of FIN 46R, which occurs if it is deemed to be a
VIE. The Company consolidates VIEs when it is determined to be the primary
beneficiary as defined by FIN 46R.





Included in the
Company’s consolidated financial statements is PNBV, a VIE created in 1996 to
refinance debt originally issued in connection with sale and leaseback
transactions.





PNBV was
established to purchase a portion of the lease obligation bonds issued in
connection with the Company's 1987 sale and leaseback of its interests in the
Perry Plant and Beaver Valley Unit 2. The Company used debt and available funds
to purchase the notes issued by PNBV. Ownership of PNBV includes a three-percent
equity interest by a nonaffiliated third party and a three-percent equity
interest held by OES Ventures, a wholly owned subsidiary of the Company. As
required by FIN 46R, consolidation of PNBV as of December 31, 2003 changed
the previously reported trust investment of $361 million to an investment in
collateralized lease bonds of $372 million. The $11 million increase represented
the minority interest in the total assets of PNBV.





Through its
investment in PNBV, the Company has variable interests in certain owner trusts
that acquired the interests in the Perry Plant and Beaver Valley Unit 2. The
Company has concluded that it was not the primary beneficiary of the owner
trusts and 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 sale-leaseback agreements upon the occurrence of
certain contingent events that it 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 agreement, the Company has net minimum discounted lease
payments of $673 million that would not be payable if the casualty value
payments are made.








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 recommendations that were to be implemented
subsequent to 2004 and will continue to periodically assess the FERC-ordered
Reliability Study recommendations for forecasted 2009 system conditions,
recognizing revised load forecasts and other changing system conditions which
may impact the recommendations. Thus far, implementation of the recommendations
has not required, nor is expected to require, substantial investment in new, or
material upgrades, to existing equipment. FirstEnergy notes, however, that FERC
or other applicable government agencies and reliability coordinators may take a
different view as to recommended enhancements or may recommend additional
enhancements in the future that could require additional, material expenditures.
Finally, the PUCO is continuing to review the FirstEnergy filing that addressed
upgrades to control room computer hardware and software and enhancements to the
training of control room operators, before determining the next steps, if any,
in the proceeding.


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





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





*Ohio-*





In October 2003, OE
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 OE's transition
plan market development period. On February 24, 2004, OE 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, OE accepted the Rate Stabilization Plan as
modified and approved by the PUCO on August 4, 2004. In the second quarter
of 2004, OE 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.





35


The revised Rate
Stabilization Plan extends current generation prices through 2008, ensuring
adequate generation supply at stabilized prices, and continues OE'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 2006 to as late as 2007;·
    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 OE 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.


On
December 30, 2004, OE filed an application with the PUCO seeking tariff
adjustments to recover increases of approximately $14 million in transmission
and ancillary service costs beginning January 1, 2006. OE 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.


*Pennsylvania-*


Pennsylvania
enacted its electric utility competition law in 1996 with the phase-in of
customer choice for generation suppliers completed as of January 1, 2001. In
1998, the PPUC authorized a rate restructuring plan for Penn, which essentially
resulted in the deregulation of Penn’s generation business. Under the rate
restructuring plan, Penn is entitled to recover $236 million of stranded costs
through the CTC that began in 1999 and ends in 2006.





**9.**
    **CAPITALIZATION:**





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





Under the Company’s
first mortgage indenture, the Company’s consolidated retained earnings
unrestricted for payment of cash dividends on the Company’s common stock were
$438.2 million as of December 31, 2004.





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





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





The Company has
eight million authorized and unissued shares of preference stock having no
par value.





*Preferred Stock
Subject To Mandatory Redemption-*





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





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





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





*Other Long-term
Debt-*





Each of the
Companies 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 also has a 1998 general
mortgage under which it issues mortgage bonds based upon the pledge of a like
amount of first mortgage bonds as security. These mortgage bonds therefore
effectively enjoy the same lien on that property. The Companies have various
debt covenants under their respective financing arrangements. The most
restrictive of their debt covenants relate to the nonpayment of interest and/or
principal on debt which could trigger a default and the maintenance of minimum
fixed charge ratios and debt to capitalization ratios. There also exists
cross-default provisions among financing arrangements of FirstEnergy and the
Companies.





36





Based on the amount
of FMB authenticated by the respective mortgage bond trustees through
December 31, 2004, the Companies' annual sinking fund requirements for all
FMB issued under the various mortgage indentures amounts to $40 million. The
Companies expect to deposit funds with their respective mortgage bond trustees
in 2005 that will then be withdrawn upon the surrender for cancellation of a
like principal amount of FMB, specifically authenticated for such purposes
against unfunded property additions or against previously retired FMB. This
method can result in minor increases in the amount of the annual sinking fund
requirement.


Sinking fund
requirements for FMB and maturing long-term debt (excluding capital leases) for
the next five years are:




***(In
      millions)***2005
    
    $
    3962006
    
    
    62007
    
    
    62008
    
    
    2292009
    
    
    2





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. These amounts are $261
million and $50 million in 2005 and 2008, respectively, representing the next
time the debt holders may exercise this provision.





The Companies'
obligations to repay certain pollution control revenue bonds are secured by
several series of FMB. Certain pollution control revenue bonds are entitled to
the benefit of irrevocable bank LOCs of $168.5 million and noncancelable
municipal bond insurance policies of $449.8 million to pay principal of, or
interest on, the pollution control revenue bonds. To the extent that drawings
are made under the LOCs or the policies, the Companies are entitled to a credit
against their obligation to repay those bonds. The Companies pay annual fees of
1.0% to 1.7% of the amounts of the LOCs to the issuing banks and are 0.20% to
0.55% of the amounts of the policies to the insurers and are obligated to
reimburse the banks or insurers, as the case may be, for any drawings
thereunder.





The Company had no
unsecured borrowings as of December 31, 2004 under a $250 million long-term
revolving credit facility agreement which expires May 12, 2005. The Company
currently pays an annual facility fee of 0.20% on the total credit facility
amount. The Company had no unsecured borrowings as of December 31, 2004
under a $125 million long-term revolving credit facility which expires
October 23, 2006. The Company currently pays an annual facility fee of
0.25% on the total credit facility amount. The fees are subject to change based
on changes to the Company's credit ratings.





OES Finance,
Incorporated, a wholly owned subsidiary of the Company, had maintained
certificates of deposits pledged as collateral to secure reimbursement
obligations relating to certain LOCs supporting the Company's obligations to
lessors under the Beaver Valley Unit 2 sale and leaseback arrangements. In June
2004, these LOCs were replaced by a new LOC which did not require the collateral
deposits. The Company entered into a Credit Agreement pursuant to which a
standby LOC was issued in support of the replacement LOCs and the issuer of the
standby LOC obtained the right to pledge or assign participations in the
Company's reimbursement obligations to a trust. The trust then issued and sold
trust certificates to institutional investors that were designed to be the
credit equivalent of an investment directly in the Company. The certificates of
deposit were cancelled and the Company received cash proceeds of $278 million in
the third quarter of 2004.





**10.**
    **ASSET
      RETIREMENT OBLIGATIONS:**





In January 2003,
the Companies implemented SFAS 143, which provides accounting standards for
retirement obligations associated with tangible long-lived assets. This
statement requires recognition of the fair value of a liability for an ARO in
the period in which it is incurred. The associated asset retirement costs are
capitalized as part of the carrying amount of the long-lived asset. Over time
the capitalized costs are depreciated and the present value of the asset
retirement liability increases, resulting in a period expense. However,
rate-regulated entities may recognize a regulatory asset or liability instead of
an expense if the criteria for such treatment are met. Upon retirement, a gain
or loss would be recognized if the cost to settle the retirement obligation
differs from the carrying amount.





The Companies
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 $297.6 million, including accumulated accretion for the
period from the date the liability was incurred to the date of adoption.
Accretion was $21 million and $20 million during 2004 and 2003, respectively,
bringing the ARO liability as of December 31, 2004 to $339 million. The ARO
includes the Companies' obligation for nuclear decommissioning of the Beaver
Valley and Perry generating facilities. The Companies' share of the obligation
to decommission these units was developed based on site specific studies
performed by an independent engineer. The Companies utilized an expected cash
flow approach to measure the fair value of the nuclear decommissioning ARO. The
Companies maintain 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
$436 million.





37





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
      income
    
    $
    356Increase
      (Decrease):Elimination
      of decommissioning expense
    
    
    30Depreciation
      of asset retirement cost
    
    
    (1
    )Accretion of
      ARO liability
    
    
    (11
    )Non-regulated
      generation cost of removal
      component,
      net
    
    
    5Income tax
      effect
    
    
    (9
    )Net earnings
      increase
    
    
    14Net income
      adjusted
    
    $
    370








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
    
    $
    318
    
    $
    298Accretion
    
    
    21
    
    
    20Ending
      balance as of December 31
    
    $
    339
    
    $
    318








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
    
    $
    279Accretion
    
    
    19Ending
      balance as of December 31
    
    $
    298








**11.**
    **SHORT-TERM
      BORROWINGS AND BANK LINES OF CREDIT:**





Short-term
borrowings outstanding as of December 31, 2004, consisted of $25 million of
OE bank borrowings and $142 million of OES Capital, Incorporated borrowings. OES
Capital is a wholly owned subsidiary of OE whose borrowings are secured by
customer accounts receivable purchased from OE. OES Capital can borrow up to
$170 million under a receivables financing arrangement at rates based on certain
bank commercial paper and is required to pay an annual fee of 0.25% on the
amount of the entire finance limit. The receivables financing agreement expires
in October 2005. Penn has, through a wholly owned subsidiary, a receivables
financing arrangement that provides a combined borrowing capability of up to
$11.9 million at rates based on bank commercial paper rates. The financing
arrangements require payment of an annual facility fee of 0.40% on the entire
finance limit. Penn's receivables financing agreements expire in March 2005 and
is expected to be renewed prior to expiration.





OE has various
bi-lateral credit facilities with domestic banks that provide for borrowings of
up to $34 million under various interest rate options. To assure the
availability of these lines, OE is required to pay annual commitment fees that
vary from 0.20% to 0.25% of total lender commitments. These lines expire at
various times during 2005. The weighted average interest rates on short-term
borrowings outstanding as of December 31, 2004 and 2003 were 2.28% and
1.16%, respectively.





38





**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 their ownership
and leasehold interests in the Beaver Valley Station and the Perry Plant, the
Companies' 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 $192.0
million per incident but not more than $19.1 million in any one year for each
incident.





The Companies are
also insured as to their respective interests in Beaver Valley and Perry under
policies issued to the operating company for each plant. Under these policies,
up to $2.75 billion is provided for property damage and decontamination and
decommissioning costs. The Companies have also obtained approximately $677.3
million of insurance coverage for replacement power costs for their respective
interests in Beaver Valley and Perry. Under these policies, the Companies can be
assessed a maximum of approximately $32 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 Companies
intend 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 Companies' 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 Companies'
insurance policies, or to the extent such insurance becomes unavailable in the
future, the Companies would remain at risk for such costs.





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





Various federal,
state and local authorities regulate the Companies with regard to air and water
quality and other environmental matters. The effects of compliance on the
Companies with regard to environmental matters could have a material adverse
effect on the Companies' earnings and competitive position. These environmental
regulations affect the Companies' earnings and competitive position to the
extent that they compete 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 Companies believe they
are in material compliance with existing regulations but are 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 Companies 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. The Companies
cannot predict what action the EPA may take in the future with respect to the
interim enforcement policy.
 
 The Companies
believe they are complying with SO2reduction requirements under the
Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more
electricity from lower-emitting plants, and/or using emission allowances.
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 Companies' 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 Companies believe their
facilities are complying with the NOxbudgets established under State
Implementation Plans (SIPs) through combustion controls and post-combustion
controls, including Selective Catalytic Reduction and Selective Non-Catalytic
Reduction systems, and/or using emission allowances.


39





*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 SO2emissions
in two phases (Phase I in 2010 and Phase II in 2015). According to the EPA,
SO2emissions 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 Companies 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 SO 2 and NO x 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.


*W. H. Sammis
Plant-*


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


*Regulation of
Hazardous Waste-*


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


40





*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 Companies
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 CO2emissions per KWH of electricity generated by the Companies is lower than
many regional competitors due to the Companies' diversified generation sources
which includes low or non-CO2 emitting gas-fired and nuclear
generators.






*Clean Water
Act-*


Various water
quality regulations, the majority of which are the result of the federal Clean
Water Act and its amendments, apply to the Companies' plants. In addition, Ohio,
and Pennsylvania have water quality standards applicable to the Companies'
operations. As provided in the Clean Water Act, authority to grant federal
National Pollutant Discharge Elimination System water discharge permits can be
assumed by a state. Ohio 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 Companies 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. FirstEnergy is unable to predict the outcome of
such studies. Depending on the outcome of such studies, the future cost of
compliance with these standards may require material capital
expenditures.





**(C)**
    **OTHER
      LEGAL PROCEEDINGS-**





*Power Outages
and Related Litigation-*


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


41





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.





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 FirstEnergy's
or its subsidiaries' financial condition and results of operations.





*Legal
Matters-*





There are various
lawsuits, claims (including claims for asbestos exposure) and proceedings
related to the Companies' normal business operations pending against the Company
and its subsidiaries. The most significant not otherwise discussed above are
described below.





On August 12, 2004,
the NRC notified FENOC that it will increase its regulatory oversight of the
Perry Nuclear Power Plant as a result of problems with safety system equipment
over the past two years. FENOC operates the Perry Nuclear Power Plant, in which
the Companies have a 35.24% interest. Although the NRC noted that the plant
continues to operate safely, the agency has indicated that its increased
oversight will include an extensive NRC team inspection to assess the equipment
problems and the sufficiency of FENOC's corrective actions. The outcome of these
matters could include NRC enforcement action or other impacts on operating
authority. As a result, these matters could have a material adverse effect on
FirstEnergy's or its subsidiaries' financial condition.





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 (the Company has
no interest in Davis-Besse) has 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 the Company or its subsidiaries has legal liability
or is otherwise made subject to liability based on any of the above matters, it
could have a material adverse effect on the Company'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 Companies are currently evaluating this standard but do not
expect it to have a material impact on the financial statements.





42





*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 Companies after June 30, 2005. The Companies are
currently evaluating this standard but do 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 Companies will continue to
evaluate its investments as required by existing authoritative
guidance.





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




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





43





**14.**
    **SUMMARY
      OF QUARTERLY FINANCIAL DATA (UNAUDITED):**





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





**March
      31,**
    
    **June
      30,**
    
    **September
      30,**
    
    **December
      31,****Three
      Months Ended**
    
    **2004**
    
    **2004**
    
    **2004**
    
    **2004*****(In
      millions)***Operating
      Revenues
    
    $
    743.3
    
    $
    718.4
    
    $
    766.3
    
    $
    717.6Operating
      Expenses and Taxes
    
    
    660.9
    
    
    632.2
    
    
    670.8
    
    
    646.2Operating
      Income
    
    
    82.4
    
    
    86.2
    
    
    95.5
    
    
    71.4Other
      Income
    
    
    12.5
    
    
    20.7
    
    
    17.2
    
    
    23.7Net Interest
      Charges
    
    
    18.8
    
    
    19.5
    
    
    10.0
    
    
    18.6Net
      Income
    
    $
    76.1
    
    $
    87.4
    
    $
    102.7
    
    $
    76.5Earnings on
      Common Stock
    
    $
    75.5
    
    $
    86.7
    
    $
    102.1
    
    $
    76.0








**March
      31,**
    
    **June
      30,**
    
    **September
      30,**
    
    **December
      31,****Three
      Months Ended**
    
    **2003**
    
    **2003**
    
    **2003**
    
    **2003*****(In
      millions)***Operating
      Revenues
    
    $
    742.8
    
    $
    673.7
    
    $
    774.7
    
    $
    734.1Operating
      Expenses and Taxes
    
    
    672.7
    
    
    609.7
    
    
    686.2
    
    
    619.8Operating
      Income
    
    
    70.1
    
    
    64.0
    
    
    88.5
    
    
    114.3Other
      Income
    
    
    13.5
    
    
    15.4
    
    
    15.9
    
    
    22.0Net Interest
      Charges
    
    
    26.5
    
    
    34.1
    
    
    23.6
    
    
    26.6Income Before
      Cumulative Effect of
      Accounting
      Change
    
    
    57.1
    
    
    45.3
    
    
    80.8
    
    
    109.7Cumulative
      Effect of Accounting Change (Net
      of Income
      Taxes)
    
    
    31.7
    
    
    --
    
    
    --
    
    
    --Net
      Income
    
    $
    88.8
    
    $
    45.3
    
    $
    80.8
    
    $
    109.7Earnings on
      Common Stock
    
    $
    88.1
    
    $
    44.7
    
    $
    80.1
    
    $
    109.0








44