**UNITED
STATES SECURITIES AND EXCHANGE COMMISSION**


**Washington,
D. C. 20549**





**FORM
10-Q**


**(Mark
One)**


**[X]
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE**


**SECURITIES
EXCHANGE ACT OF 1934**





**For the
quarterly period ended March 31, 2005**





**OR**





**[ ]
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE**


**SECURITIES
EXCHANGE ACT OF 1934**





**For
      the transition period from**
    
    **to**


**Commission**
    **Registrant;
      State of Incorporation;**
    **I.R.S.
      Employer****File
      Number**
    **Address;
      and Telephone Number**
    **Identification
      No.****333-21011**
    **FIRSTENERGY
      CORP.**
    **34-1843785****(An
      Ohio Corporation)****76
      South Main Street****Akron,
      OH 44308****Telephone
      (800)736**-**3402****1-2578**
    **OHIO
      EDISON COMPANY**
    **34-0437786****(An
      Ohio Corporation)****c/o
      FirstEnergy Corp.****76
      South Main Street****Akron,
      OH 44308****Telephone
      (800)736**-**3402****1-2323**
    **THE
      CLEVELAND ELECTRIC ILLUMINATING COMPANY**
    **34-0150020****(An
      Ohio Corporation)****c/o
      FirstEnergy Corp.****76
      South Main Street****Akron,
      OH 44308****Telephone
      (800)736**-**3402****1-3583**
    **THE
      TOLEDO EDISON COMPANY**
    **34-4375005****(An
      Ohio Corporation)****c/o
      FirstEnergy Corp.****76
      South Main Street****Akron,
      OH 44308****Telephone
      (800)736**-**3402****1-3491**
    **PENNSYLVANIA
      POWER COMPANY**
    **25-0718810****(A
      Pennsylvania Corporation)****c/o
      FirstEnergy Corp.****76
      South Main Street****Akron,
      OH 44308****Telephone
      (800)736**-**3402****1-3141**
    **JERSEY
      CENTRAL POWER & LIGHT COMPANY**
    **21-0485010****(A New
      Jersey Corporation)****c/o
      FirstEnergy Corp.****76
      South Main Street****Akron,
      OH 44308****Telephone
      (800)736**-**3402****1-446**
    **METROPOLITAN
      EDISON COMPANY**
    **23-0870160****(A
      Pennsylvania Corporation)****c/o
      FirstEnergy Corp.****76
      South Main Street****Akron,
      OH 44308****Telephone
      (800)736**-**3402****1-3522**
    **PENNSYLVANIA
      ELECTRIC COMPANY**
    **25-0718085****(A
      Pennsylvania Corporation)****c/o
      FirstEnergy Corp.****76
      South Main Street****Akron,
      OH 44308****Telephone
      (800)736**-**3402**














Indicate by check
mark whether each of the registrants (1) has filed all reports required to
be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days.





Yes X No





Indicate by check
mark whether each registrant is an accelerated filer (as defined in Rule 12b-2
of the Act):





YesX
    No
    FirstEnergy
      Corp.Yes
    NoX
    Ohio Edison
      Company, Pennsylvania Power Company, The Cleveland Electric Illuminating
      Company, The Toledo Edison Company, Jersey Central Power &
      LightCompany,
      Metropolitan Edison Company, and Pennsylvania Electric
    Company





Indicate the number
of shares outstanding of each of the issuer's classes of common stock, as of the
latest practicable date:





**OUTSTANDING****CLASS**
    **AS OF
      MAY 2, 2005**FirstEnergy
      Corp., $.10 par value
    329,836,276Ohio Edison
      Company, no par value
    100The Cleveland
      Electric Illuminating Company, no par value
    79,590,689The Toledo
      Edison Company, $5 par value
    39,133,887Pennsylvania
      Power Company, $30 par value
    6,290,000Jersey Central
      Power & Light Company, $10 par value
    15,371,270Metropolitan
      Edison Company, no par value
    859,500Pennsylvania
      Electric Company, $20 par value
    5,290,596





FirstEnergy Corp. is
the sole holder of Ohio Edison Company, The Cleveland Electric Illuminating
Company, The Toledo Edison Company, Jersey Central Power & Light Company,
Metropolitan Edison Company and Pennsylvania Electric Company common stock. Ohio
Edison Company is the sole holder of Pennsylvania Power Company common stock.





This combined Form
10-Q is separately filed by FirstEnergy Corp., Ohio Edison Company, Pennsylvania
Power Company, The Cleveland Electric Illuminating Company, The Toledo Edison
Company, Jersey Central Power & Light Company, Metropolitan Edison Company
and Pennsylvania Electric Company. Information contained herein relating to any
individual registrant is filed by such registrant on its own behalf. No
registrant makes any representation as to information relating to any other
registrant, except that information relating to any of the FirstEnergy
subsidiary registrants is also attributed to FirstEnergy Corp.





This Form 10-Q
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, the continued
ability of our regulated utilities to collect transition and other charges,
maintenance costs being higher than anticipated, legislative and regulatory
changes (including revised environmental requirements), the receipt of approval
from and entry of a final order by the U.S. District Court, Southern District of
Ohio, on the pending settlement agreement resolving the New Source Review
litigation and the uncertainty of the timing and amounts of the capital
expenditures (including that such amounts could be higher than anticipated) or
levels of emission reductions related to this settlement, adverse regulatory or
legal decisions and outcomes (including revocation of necessary licenses or
operating permits, fines or other enforcement actions and remedies) of
government investigations and oversight, including by the Securities and
Exchange Commission, the United States Attorney’s Office and the Nuclear
Regulatory Commission as disclosed in the registrants’ Securities and Exchange
Commission filings, generally, and with respect to the Davis-Besse Nuclear Power
Station outage and heightened scrutiny at the Perry Nuclear Power Plant in
particular, the availability and cost of capital, the continuing availability
and operation of generating units, the inability to accomplish or realize
anticipated benefits of strategic goals, the ability to improve electric
commodity margins and to experience growth in the distribution business, the
ability to access the public securities and other capital markets, further
investigation into the causes of the August 14, 2003 regional power outages
and the outcome, cost and other effects of present and potential legal and
administrative proceedings and claims related to the outages, the final outcome
in the proceeding related to FirstEnergy's Application for a Rate Stabilization
Plan in Ohio, the risks and other factors discussed from time to time in the
registrants' Securities and Exchange Commission filings, including their annual
report on Form 10-K for the year ended December 31, 2004, and other similar
factors. The registrants expressly disclaim any current intention to update any
forward-looking statements contained in this document as a result of new
information, future events, or otherwise.


















**TABLE OF
CONTENTS**








**Pages****Glossary
      of Terms**
    iii-iv**Part
      I.****Financial
      Information****Items 1. and 2. - Financial Statements and Management’s Discussion and
      Analysis of****Results of Operation and Financial Condition**Notes to
      Consolidated Financial Statements
    1-18**FirstEnergy Corp.**Consolidated
      Statements of Income
    19Consolidated
      Statements of Comprehensive Income
    20Consolidated
      Balance Sheets
    21Consolidated
      Statements of Cash Flows
    22Report of
      Independent Registered Public Accounting Firm
    23Management's
      Discussion and Analysis of Results of Operations andFinancial
      Condition
    24-45**Ohio Edison Company**Consolidated
      Statements of Income and Comprehensive Income
    46Consolidated
      Balance Sheets
    47Consolidated
      Statements of Cash Flows
    48Report of
      Independent Registered Public Accounting Firm
    49Management's
      Discussion and Analysis of Results of Operations andFinancial
      Condition
    50-58**The Cleveland Electric Illuminating Company**Consolidated
      Statements of Income and Comprehensive Income
    59Consolidated
      Balance Sheets
    60Consolidated
      Statements of Cash Flows
    61Report of
      Independent Registered Public Accounting Firm
    62Management's
      Discussion and Analysis of Results of Operations andFinancial
      Condition
    63-71**The Toledo Edison Company**Consolidated
      Statements of Income and Comprehensive Income
    72Consolidated
      Balance Sheets
    73Consolidated
      Statements of Cash Flows
    74Report of
      Independent Registered Public Accounting Firm
    75Management's
      Discussion and Analysis of Results of Operations andFinancial
      Condition
    76-83**Pennsylvania
      Power Company**ConsolidatedStatements of
      Income and Comprehensive Income
    84ConsolidatedBalance
      Sheets
    85ConsolidatedStatements of
      Cash Flows
    86Report of
      Independent Registered Public Accounting Firm
    87Management's
      Discussion and Analysis of Results of Operations andFinancial
      Condition
    88-94













i





**TABLE OF
CONTENTS (Cont'd)**








**Pages****Jersey Central Power & Light Company**Consolidated
      Statements of Income and Comprehensive Income
    95Consolidated
      Balance Sheets
    96Consolidated
      Statements of Cash Flows
    97Report of
      Independent Registered Public Accounting Firm
    98Management's
      Discussion and Analysis of Results of Operations andFinancial
      Condition
    99-105**Metropolitan Edison Company**Consolidated
      Statements of Income and Comprehensive Income
    106Consolidated
      Balance Sheets
    107Consolidated
      Statements of Cash Flows
    108Report of
      Independent Registered Public Accounting Firm
    109Management's
      Discussion and Analysis of Results of Operations andFinancial
      Condition
    110-115**Pennsylvania Electric Company**Consolidated
      Statements of Income and Comprehensive Income
    116Consolidated
      Balance Sheets
    117Consolidated
      Statements of Cash Flows
    118Report of
      Independent Registered Public Accounting Firm
    119Management's
      Discussion and Analysis of Results of Operations andFinancial
      Condition
    120-125**Item 3.****Quantitative
      and Qualitative Disclosures About Market Risk**
    126**Item 4.****Controls
      and Procedures**
    126**Part
      II.****Other
      Information****Item 1.****Legal
      Proceedings**
    127**Item 2.****Changes
      in Securities, Use of Proceeds and Issuer Purchases of Equity
      Securities**
    127**Item 6.****Exhibits**
    130-142













ii










**GLOSSARY OF
TERMS**





The following
abbreviations and acronyms are used in this report to identify FirstEnergy Corp.
and its current and former subsidiaries:





ATSI
    American
      Transmission Systems, Inc., owns and operates transmission
      facilitiesCEI
    The Cleveland
      Electric Illuminating Company, an Ohio electric utility operating
      subsidiaryCFC
    Centerior
      Funding Corporation, a wholly owned finance subsidiary of
    CEICompanies
    OE, CEI, TE,
      Penn, JCP&L, Met-Ed and PenelecEUOC
    Electric
      Utility Operating Companies (OE, CEI, TE, Penn, JCP&L, Met-Ed,
      Penelec, and ATSI)FENOC
    FirstEnergy
      Nuclear Operating Company, operates nuclear generating
      facilitiesFES
    FirstEnergy
      Solutions Corp., provides energy-related products and
    servicesFESC
    FirstEnergy
      Service Company, provides legal, financial, and other corporate support
      servicesFGCO
    FirstEnergy
      Generation Corp., operates nonnuclear generating
  facilitiesFirstCom
    First
      Communications, LLC, provides local and long-distance telephone
      serviceFirstEnergy
    FirstEnergy
      Corp., a registered public utility holding companyFSG
    FirstEnergy
      Facilities Services Group, LLC, the parent company of several heating,
      ventilation,air
      conditioning and energy management companiesGPU
    GPU, Inc.,
      former parent of JCP&L, Met-Ed and Penelec, which merged with
      FirstEnergy onNovember 7,
      2001JCP&L
    Jersey Central
      Power & Light Company, a New Jersey electric utility operating
      subsidiaryJCP&L
      Transition
    JCP&L
      Transition Funding LLC, a Delaware limited liability company and issuer of
      transition bondsMet-Ed
    Metropolitan
      Edison Company, a Pennsylvania electric utility operating
      subsidiaryMYR
    MYR Group,
      Inc., a utility infrastructure construction service
  companyOE
    Ohio Edison
      Company, an Ohio electric utility operating subsidiaryOE
      Companies
    OE and PennOhio
      Companies
    CEI, OE and
      TEPenelec
    Pennsylvania
      Electric Company, a Pennsylvania electric utility operating
      subsidiaryPenn
    Pennsylvania
      Power Company, a Pennsylvania electric utility operating subsidiary of
      OEPNBV
    PNBV Capital
      Trust, a special purpose entity created by OE in 1996Shippingport
    Shippingport
      Capital Trust, a special purpose entity created by CEI and TE in
      1997TE
    The Toledo
      Edison Company, an Ohio electric utility operating
    subsidiary





The following
abbreviations and acronyms are used to identify frequently used terms in this
report:





AOCL
    Accumulated
      Other Comprehensive LossAPB
    Accounting
      Principles BoardAPB
      25
    APB Opinion
      No. 25, "Accounting for Stock Issued to Employees"APB
      29
    APB Opinion
      No. 29, “Accounting for Nonmonetary
      Transactions”ARO
    Asset
      Retirement ObligationBGS
    Basic
      Generation ServiceCO2
    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 CertainInvestments”EITF
      04-13
    EITF Issue No.
      04-13, “Accounting for Purchases and
      Sales of Inventory with the SameCounterparty”EITF
      99-19
    EITF Issue No.
      99-19, “Reporting Revenue Gross as a
      Principal versus Net as an Agent”EPA
    Environmental
      Protection AgencyFASB
    Financial
      Accounting Standards BoardFERC
    Federal Energy
      Regulatory CommissionFIN
    FASB
      InterpretationFIN
      46R
    FIN 46
      (revised December 2003), "Consolidation of Variable Interest
      Entities"FIN
      47
    FASB
      Interpretation 47, “Accounting for
      Conditional Asset Retirement Obligations - aninterpretation
      of FASB Statement No. 143”FMB
    First Mortgage
      BondsFSP
    FASB Staff
      PositionFSP EITF
      03-1-1
    FASB Staff
      Position No. EITF Issue 03-1-1, "Effective Date of Paragraphs 10-20 of
      EITF IssueNo. 03-1,*The
      Meaning of Other-Than-Temporary Impairment and Its Application to Certain**Investments"*













iii


GLOSSARY OF TERMS
Cont'd


FSP
      109-1
    FASB Staff
      Position No. 109-1, “Application of
      FASB Statement No. 109, Accounting for IncomeTaxes, to the
      Tax Deduction on Qualified Production Activities Provided by the American
      JobsCreation Act
      of 2004”GAAP
    Accounting
      Principles Generally Accepted in the United StatesHVAC
    Heating,
      Ventilation and Air-conditioningKWH
    Kilowatt-hoursLOC
    Letter of
      CreditMISO
    Midwest
      Independent Transmission System Operator, Inc.MSG
    Market Support
      GenerationMTC
    Market
      Transition ChargeMW
    MegawattsNAAQS
    National
      Ambient Air Quality StandardsNERC
    North American
      Electric Reliability CouncilNJBPU
    New Jersey
      Board of Public UtilitiesNOV
    Notices of
      ViolationNOX
    Nitrogen
      OxideNRC
    Nuclear
      Regulatory CommissionNUG
    Non-Utility
      GenerationOCC
    Ohio
      Consumers' CounselOCI
    Other
      Comprehensive IncomeOPEB
    Other
      Post-Employment BenefitsPCAOB
    Public Company
      Accounting Oversight Board (United States)PJM
    PJM
      Interconnection L.L.C.PLR
    Provider of
      Last ResortPPUC
    Pennsylvania
      Public Utility CommissionPRP
    Potentially
      Responsible PartyPUCO
    Public
      Utilities Commission of OhioPUHCA
    Public Utility
      Holding Company ActRTC
    Regulatory
      Transition ChargeS&P
    Standard &
      Poor’s Ratings ServiceSBC
    Societal
      Benefits ChargeSEC
    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
      123
    SFAS No. 123,
      "Accounting for Stock-Based Compensation"SFAS
      123(R)
    SFAS No. 123
      (revised 2004), “Share-Based
      Payment”SFAS
      131
    SFAS No. 131,
      “Disclosures about Segments of an
      Enterprise and Related Information”SFAS
      133
    SFAS No. 133,
      “Accounting for Derivative Instruments
      and Hedging Activities”SFAS
      140
    SFAS No. 140,
      “Accounting for Transfers and
      Servicing of Financial Assets andExtinguishment
      of Liabilities”SFAS
      144
    SFAS No. 144,
      "Accounting for the Impairment or Disposal of Long-Lived
      Assets"SO2
    Sulfur
      DioxideTBC
    Transition
      Bond ChargeTMI-2
    Three Mile
      Island Unit 2VIE
    Variable
      Interest Entity








iv







**PART I.
FINANCIAL INFORMATION**





**FIRSTENERGY
CORP. AND SUBSIDIARIES**


**OHIO EDISON
COMPANY AND SUBSIDIARIES**


**THE
CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARIES**


**THE TOLEDO
EDISON COMPANY AND SUBSIDIARY**


**PENNSYLVANIA
POWER COMPANY AND SUBSIDIARY**


**JERSEY
CENTRAL POWER & LIGHT COMPANY AND SUBSIDIARIES**


**METROPOLITAN
EDISON COMPANY AND SUBSIDIARIES**


**PENNSYLVANIA
ELECTRIC COMPANY AND SUBSIDIARIES**





**NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS**


**(UNAUDITED)**








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





FirstEnergy’s
principal business is the holding, directly or indirectly, of all of the
outstanding common stock of its eight principal electric utility operating
subsidiaries: OE, CEI, TE, Penn, ATSI, JCP&L, Met-Ed and Penelec. Penn is a
wholly owned subsidiary of OE. FirstEnergy's consolidated financial statements
also include its other principal subsidiaries: FENOC, FES and its subsidiary
FGCO, FESC, FSG, and MYR.





FirstEnergy and its
subsidiaries follow GAAP and comply with the regulations, orders, policies and
practices prescribed by the SEC, FERC and, as applicable, PUCO, PPUC and NJBPU.
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 disclosure of
contingent assets and liabilities. Actual results could differ from these
estimates. The reported results of operations are not indicative of results of
operations for any future period.





These statements
should be read in conjunction with the financial statements and notes included
in the combined Annual Report on Form 10-K for the year ended December 31,
2004 for FirstEnergy and the Companies. The consolidated unaudited financial
statements of FirstEnergy and each of the Companies reflect all normal recurring
adjustments that, in the opinion of management, are necessary to fairly present
results of operations for the interim periods. Certain businesses divested in
the first quarter of 2005 have been classified as discontinued operations on the
Consolidated Statements of Income (see Note 6). As discussed in Note 15, interim
period segment reporting in 2004 was reclassified to conform with the current
year business segment organizations and operations.





FirstEnergy and its
subsidiaries consolidate all majority-owned subsidiaries over which they
exercise control and, when applicable, entities for which they have 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 FirstEnergy
and its subsidiaries have the ability to exercise significant influence, but not
control, are accounted for under the equity method. Under the equity method, the
interest in the entity is reported as an investment in the Consolidated Balance
Sheet and the percentage share of the entity’s earnings is reported in the
Consolidated Statement of Income.





FirstEnergy's and
the Companies' independent registered public accounting firm has performed
reviews of, and issued reports on, these consolidated interim financial
statements in accordance with standards established by the PCAOB. Pursuant to
Rule 436(c) under the Securities Act of 1933, their reports of those reviews
should not be considered a report within the meaning of Section 7 and 11 of that
Act, and the independent registered public accounting firm’s liability under
Section 11 does not extend to them.





**2. -
ACCOUNTING FOR CERTAIN WHOLESALE ENERGY TRANSACTIONS**




FES engages in
purchase and sale transactions in the PJM Market to support the supply of
end-use customers, including its BGS obligation in New Jersey and PLR
requirements in Pennsylvania. In conjunction with FirstEnergy's dedication of
its Beaver Valley Plant to PJM on January 1, 2005, FES began accounting
for purchase and sale transactions in the PJM Market based on its net hourly
position -- recording each hour as either an energy purchase or energy sale.
Hourly energy positions are aggregated to recognize gross purchases and sales
for the month.





1





This revised method
of accounting, which has no impact on net income, is consistent with the
practice of other energy companies that have dedicated generating capacity to
PJM and correlates with PJM's scheduling and reporting of hourly energy
transactions. In addition, FES applies this methodology to purchase and sale
transactions in MISO's energy market, which became active April 1, 2005.


For periods prior to
January 1, 2005, FirstEnergy did not have dedicated generating capacity in
PJM and as such, FES recognized purchases and sales in the PJM Market by
recording each discrete transaction. Under these transactions, FES would often
buy a specific quantity of energy at a certain location in PJM and
simultaneously sell a specific quantity of energy at a different location.
Physical delivery occurred and the risks and rewards of ownership transferred
with each transaction. FES has accounted
for these transactions on a gross basis in accordance with EITF
99-19.





The FASB's Emerging
Issues Task Force is currently considering EITF 04-13, which relates to the
accounting for purchases and sales of inventory with the same counterparty. The
EITF is expected to address under what circumstances two or more transactions
with the same counterparty should be viewed as a single nonmonetary transaction
within the scope of APB 29. If the EITF were to determine that transactions such
as FES' purchases and sales in the PJM Market should be accounted for as
nonmonetary transactions, FES would report the transactions prior to
January 1, 2005 on a net basis. This requirement would have no impact on
net income, but would reduce both wholesale revenue and purchased power
expense by $280 million for the first quarter of 2004.





**3. -
DEPRECIATION**





During the second
half of 2004, FirstEnergy engaged an independent third party to assist in
reviewing the service lives of its fossil generation units. This study was
completed in the first quarter of 2005. As a result of the analysis, FirstEnergy
extended the estimated service lives of its fossil generation units for periods
ranging from 11 to 33 years during the first quarter of 2005. Extension of the
service lives will provide improved matching of depreciation expense with the
expected economic lives of those generation units. The change in estimate
resulted in a $5.9 million increase (CEI - $2.1 million, OE - $3.3 million, Penn
- $0.1 million, TE - $0.5 million, FGCO - $(0.1) million) in income before
discontinued operations and net income ($0.02 per share of common stock) during
the first quarter of 2005.





**4. -
EARNINGS PER SHARE**





Basic earnings per
share are computed using the weighted average of actual common shares
outstanding during the respective period as the denominator. The denominator for
diluted earnings per share reflects the weighted average of common shares
outstanding plus the potential additional common shares that could result if
dilutive securities and other agreements to issue common stock were exercised.
Stock-based awards to purchase shares of common stock totaling 0.5 million in
the three months ended March 31, 2005 and 3.3 million in the three months ended
March 31, 2004, were excluded from the calculation of diluted earnings per share
of common stock because their exercise prices were greater than the average
market price of common shares during the period. The following table reconciles
the denominators for basic and diluted earnings per share from Income Before
Discontinued Operations:








**Reconciliation
      of Basic and**
    
    **Three
      Months Ended****Diluted
      Earnings per Share**
    
    **March
      31,****2005**
    
    **2004*****(In
      thousands)***Income Before
      Discontinued Operations
    
    $
    140,788
    
    $
    172,526Average Shares
      of Common Stock Outstanding:Denominator
      for basic earnings per share(weighted
      average shares outstanding)
    
    
    327,908
    
    
    327,057Assumed
      exercise of dilutive stock options and awards
    
    
    1,519
    
    
    1,977Denominator
      for diluted earnings per share
    
    
    329,427
    
    
    329,034Income Before
      Discontinued Operations per common share:Basic
    
    $
    0.43
    
    $
    0.53Diluted
    
    $
    0.42
    
    $
    0.53








2





**5. -
GOODWILL**





FirstEnergy's
goodwill primarily relates to its regulated services segment. In the three
months ended March 31, 2005, FirstEnergy adjusted goodwill related to the
divestiture of non-core operations (FES' natural gas business, the MYR
subsidiary, Power Piping Company, and a portion of its interest in FirstCom) as
further discussed in Note 6. In addition, the adjustment of the former GPU
companies' goodwill was due to the reversal of pre-merger tax reserves as a
result of property tax settlements. FirstEnergy
estimates that completion of transition cost recovery (see Note 13) will not
result in an impairment of goodwill relating to its regulated business segment.





A summary of the
changes in goodwill for the three months ended March 31, 2005 is shown
below.








**FirstEnergy**
    
    **CEI**
    
    **TE**
    
    **JCP&L**
    
    **Met-Ed**
    
    **Penelec*****(In
      millions)***Balance as of
      January 1, 2005
    
    $
    6,050
    
    $
    1,694
    
    $
    505
    
    $
    1,985
    
    $
    870
    
    $
    888Non-core asset
      sales
    
    
    (12
    )
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --Adjustments
      related to GPU acquisition
    
    
    (4
    )
    
    --
    
    
    --
    
    
    (1
    )
    
    (2
    )
    
    (1
    )Balance as of
      March 31, 2005
    
    $
    6,034
    
    $
    1,694
    
    $
    505
    
    $
    1,984
    
    $
    868
    
    $
    887








**6. -
DIVESTITURES AND DISCONTINUED OPERATIONS**





In December 2004,
FES' natural gas business qualified as assets held for sale in accordance with
SFAS 144. On March 31, 2005, FES completed the sale for an after-tax gain
of $5 million.





In March 2005,
FirstEnergy sold 51% of its interest in FirstCom, resulting in an after-tax gain
of $4 million. FirstEnergy will account for its remaining 31.85% interest in
FirstCom on the equity basis.





In the first quarter
of 2005, FirstEnergy sold its FSG subsidiaries, Elliott-Lewis and Spectrum, and
MYR subsidiary, Power Piping Company, resulting in an after-tax gain of $12
million. FSG's remaining subsidiaries qualified as held for sale in accordance
with SFAS 144 and are expected to be recognized as completed sales by the fourth
quarter of 2005. The assets and liabilities of these remaining FSG subsidiaries
are not material to FirstEnergy’s Consolidated Balance Sheet as of
March 31, 2005 and have therefore not been separately classified as assets
held for sale.





Net income
(including the sales gains discussed above) for Elliott-Lewis, Power Piping and
FES' natural gas business of $19 million for the first quarter of 2005 and $1
million for the first quarter of 2004 are reported as discontinued operations on
FirstEnergy's Consolidated Statements of Income. Pre-tax operating results for
these entities were $4 million for the first quarter of 2005 and $3 million for
the first quarter of 2004. Revenues associated with discontinued operations for
the first quarter of 2005 and 2004 were $191 million and $186 million,
respectively. It is not certain that the remaining FSG businesses will meet the
criteria for discontinued operations; therefore, the net loss ($2 million for
the first quarter of 2005 and $1 million for the first quarter of 2004) from
these subsidiaries has not been included in discontinued operations. See Note 15
for FSG's segment financial information.








**Three
      Months Ended****March
      31,****2005**
    
    **2004*****(In
      millions)***Discontinued
      Operations (Net of tax)Gain on
      sale:Natural gas
      business
    
    $
    5
    
    $
    --Elliot-Lewis,
      Spectrum and Power Piping
    
    
    12
    
    
    --Reclassification
      of operating income
    
    
    2
    
    
    1Total
    
    $
    19
    
    $
    1








3





**7. -
DERIVATIVE INSTRUMENTS**





FirstEnergy has
entered into fair value hedges of fixed-rate, long-term debt issues to protect
against the risk of changes in the fair value of fixed-rate debt instruments due
to lower interest rates. Swap maturities,
call options, fixed interest rates received, and interest payment dates match
those of the underlying debt obligations. As of March 31, 2005, FirstEnergy
had fixed-for-floating interest rate swap agreements with an aggregate notional
amount of $1.75 billion. During the first quarter of 2005, FirstEnergy executed
new interest rate swaps with a total notional amount of $100 million. Under
these agreements, FirstEnergy receives fixed cash flows based on the fixed
coupons of hedged securities and pays variable cash flows based on short-term
variable market interest rates. The weighted average
fixed interest rate of senior notes and subordinated debentures hedged by the
swap agreements was 6.51%. The interest rate swaps have effectively converted
that rate to a current, weighted average variable interest rate of 4.91%. Changes
in the fair value of derivatives designated as fair value hedges and the
corresponding changes in the fair value of the hedged risk attributable to a
recognized asset, liability, or unrecognized firm commitment are recorded in
earnings. Since the fair value hedges are effective, the amounts recorded will
be offset in earnings.




FirstEnergy engages
in hedging of anticipated transactions using cash flow hedges. Such transactions
include hedges of anticipated electricity and natural gas purchases and
anticipated interest payments associated with future debt issues. The effective
portion of such hedges are initially recorded in equity as other comprehensive
income or loss and are subsequently included in net income as the underlying
hedged commodities are delivered or interest payments are made. Gains and losses
from any ineffective portion of cash flow hedges are included directly in
earnings. The net deferred loss of $87 million included in AOCL as of
March 31, 2005, for derivative hedging activity, as compared to the
December 31, 2004 balance of $92 million in net deferred losses, resulted
from a $5 million reduction related to current hedging activity, a $4 million
increase due to the sale of gas business contracts and a $4 million decrease due
to net hedge losses included in earnings during the three months ended
March 31, 2005. Approximately $10 million (after tax) of the net deferred
loss on derivative instruments in AOCL as of March 31, 2005 is expected to
be reclassified to earnings during the next twelve months as hedged transactions
occur. The fair value of these derivative instruments will fluctuate from period
to period based on various market factors.


**8. - STOCK
BASED COMPENSATION**




FirstEnergy applies
the recognition and measurement principles of APB 25 and related interpretations
in accounting for its stock-based compensation plans. No material stock-based
employee compensation expense is reflected in net income as all options granted
under those plans have exercise prices equal to the market value of the
underlying common stock on the respective grant dates, resulting in
substantially no intrinsic value.


In December 2004,
the FASB issued a revision to SFAS 123 which requires expensing the fair value
of stock options (see Note 14). In April 2005, the SEC delayed the effective
date of SFAS 123(R) to annual, rather than interim, periods that begin after
June 15, 2005. The SEC’s new rule results in a six-month deferral for
FirstEnergy and other companies with a fiscal year beginning January 1. The
table below summarizes the effects on FirstEnergy’s net income and earnings per
share had FirstEnergy applied the fair value recognition provisions of SFAS 123
to stock-based employee compensation in the current reporting
periods.








**Three
      Months Ended****March
      31,****2005**
    
    **2004*****(In
      thousands)***Net income, as
      reported
    
    $
    159,726
    
    $
    173,999Add back
      compensation expensereported in
      net income, net of tax(based on APB
      25)*
    
    
    7,969
    
    
    6,694Deduct
      compensation expense basedupon estimated
      fair value, net of tax
    
    
    (11,026
    )
    
    (11,098
    )Pro forma net
      income
    
    $
    156,669
    
    $
    169,595Earnings Per
      Share of Common Stock -BasicAs
      Reported
    
    $
    0.49
    
    $
    0.53Pro
      Forma
    
    $
    0.48
    
    $
    0.52DilutedAs
      Reported
    
    $
    0.48
    
    $
    0.53Pro
      Forma
    
    $
    0.48
    
    $
    0.52





*  Includes restricted
stock, stock options, performance shares, Employee Stock Ownership Plan,


Executive Deferred
Compensation Plan and Deferred Compensation Plan for Outside
Directors.








4





FirstEnergy has
reduced its use of stock options and increased its use of performance-based,
restricted stock units. Therefore, the pro forma effects of applying SFAS 123
may not be representative of its future effect. FirstEnergy has not and does not
expect to accelerate out-of-the-money options in anticipation of implementing
SFAS 123(R) on January 1, 2006 (see Note 14 - "New Accounting Standards and
Interpretations").


**9. - ASSET
RETIREMENT OBLIGATIONS**




FirstEnergy has
identified applicable legal obligations for nuclear power plant decommissioning,
reclamation of a sludge disposal pond related to the Bruce Mansfield Plant and
closure of two coal ash disposal sites. The ARO liability of $1.095 billion as
of March 31, 2005 included $1.071 billion for nuclear decommissioning of
the Beaver Valley, Davis-Besse, Perry and TMI-2 nuclear generating facilities.
The Companies' share of the obligation to decommission these units was developed
based on site specific studies performed by an independent engineer. FirstEnergy
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 March 31, 2005,
the fair value of the decommissioning trust assets was $1.604
billion.





The following tables
provide the beginning and ending aggregate carrying amount of the ARO and the
changes to the balance during the three months ended March 31, 2005 and
2004, respectively.





**FirstEnergy**
    
    **OE**
    
    **CEI**
    
    **TE**
    
    **Penn**
    
    **JCP&L**
    
    **Met-Ed**
    
    **Penelec****ARO
      Reconciliation**
    
    ***(In
      millions)***Balance,
      January 1, 2005
    
    $
    1,078
    
    $
    201
    
    $
    272
    
    $
    194
    
    $
    138
    
    $
    73
    
    $
    133
    
    $
    66Liabilities
      incurred
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --Liabilities
      settled
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --Accretion
    
    
    17
    
    
    3
    
    
    4
    
    
    3
    
    
    2
    
    
    2
    
    
    2
    
    
    1Revisions
      in estimated cash flows
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --Balance,
      March 31, 2005
    
    $
    1,095
    
    $
    204
    
    $
    276
    
    $
    197
    
    $
    140
    
    $
    75
    
    $
    135
    
    $
    67Balance,
      January 1, 2004
    
    $
    1,179
    
    $
    188
    
    $
    255
    
    $
    182
    
    $
    130
    
    $
    110
    
    $
    210
    
    $
    105Liabilities
      incurred
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --Liabilities
      settled
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --Accretion
    
    
    19
    
    
    3
    
    
    4
    
    
    3
    
    
    2
    
    
    1
    
    
    3
    
    
    2Revisions
      in estimated cash flows
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    --Balance,
      March 31, 2004
    
    $
    1,198
    
    $
    191
    
    $
    259
    
    $
    185
    
    $
    132
    
    $
    111
    
    $
    213
    
    $
    107








**10. -
PENSION AND OTHER POSTRETIREMENT BENEFITS:**




The components of
FirstEnergy's net periodic pension cost and other postretirement benefit cost
(including amounts capitalized) as of March 31, 2005 and 2004, consisted of
the following:








**Pension
      Benefits**
    
    **Other
      Postretirement Benefits****2005**
    
    **2004**
    
    **2005**
    
    **2004*****(In
      millions)***Service cost
    
    $
    19
    
    $
    19
    
    $
    10
    
    $
    11Interest
      cost
    
    
    64
    
    
    63
    
    
    28
    
    
    33Expected
      return on plan assets
    
    
    (86
    )
    
    (71
    )
    
    (11
    )
    
    (13
    )Amortization
      of prior service cost
    
    
    2
    
    
    2
    
    
    (11
    )
    
    (12
    )Recognized net
      actuarial loss
    
    
    9
    
    
    10
    
    
    10
    
    
    11Net periodic
      cost
    
    $
    8
    
    $
    23
    
    $
    26
    
    $
    30








5





Pension and
postretirement benefit obligations are allocated to FirstEnergy’s subsidiaries
employing the plan participants. The Companies capitalize employee benefits
related to construction projects. The net periodic pension costs (credits) and
net periodic postretirement benefit costs (including amounts capitalized)
recognized by each of the Companies in the three months ended March 31,
2005 and 2004 were as follows:


**Pension
      Benefit Cost (Credit)**
    
    **Other
      Postretirement Benefit Cost****2005**
    
    **2004**
    
    **2005**
    
    **2004*****(In
      millions)***OE
    
    $
    0.2
    
    $
    1.7
    
    $
    5.8
    
    $
    7.1Penn
    
    
    (0.2
    )
    
    0.1
    
    
    1.2
    
    
    1.5CEI
    
    
    0.3
    
    
    1.6
    
    
    3.8
    
    
    5.6TE
    
    
    0.3
    
    
    0.8
    
    
    2.2
    
    
    2.0JCP&L
    
    
    (0.2
    )
    
    1.9
    
    
    2.7
    
    
    1.6Met-Ed
    
    
    (1.1
    )
    
    0.1
    
    
    0.4
    
    
    1.3Penelec
    
    
    (1.3
    )
    
    0.1
    
    
    1.9
    
    
    1.4










**11. -
VARIABLE INTEREST ENTITIES**





**Leases**





Included in
FirstEnergy’s consolidated financial statements are PNBV and Shippingport, two
VIEs created in 1996 and 1997, respectively, to refinance debt originally issued
in connection with sale and leaseback transactions. PNBV and Shippingport
financial data are included in the consolidated financial statements of OE and
CEI, respectively.





PNBV was established
to purchase a portion of the lease obligation bonds issued in connection with
OE’s 1987 sale and leaseback of its interests in the Perry Plant and Beaver
Valley Unit 2. OE 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 OE. Shippingport was established to
purchase all of the lease obligation bonds issued in connection with CEI’s and
TE’s Bruce Mansfield Plant sale and leaseback transaction in 1987. CEI and TE
used debt and available funds to purchase the notes issued by
Shippingport.





OE, CEI and TE are
exposed to losses under the applicable sale-leaseback agreements upon the
occurrence of certain contingent events that each company considers unlikely to
occur. OE, CEI and TE each have 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 applicable sale and leaseback
agreements, OE, CEI and TE have net minimum discounted lease payments of $688
million, $99 million and $566 million, respectively, that would not be payable
if the casualty value payments are made.





**Power
Purchase Agreements**




In accordance with
FIN 46R, FirstEnergy evaluated its power purchase agreements and determined that
certain NUG entities may be VIEs to the extent they own a plant that sells
substantially all of its output to the Companies and the contract price for
power is correlated with the plant’s variable costs of production. FirstEnergy,
through its subsidiaries JCP&L, Met-Ed and Penelec, maintains approximately
30 long-term power purchase agreements with NUG entities. The agreements were
structured pursuant to the Public Utility Regulatory Policies Act of 1978.
FirstEnergy was not involved in the creation of, and has no equity or debt
invested in, these entities.


FirstEnergy has
determined that for all but nine of these entities, neither JCP&L, Met-Ed
nor Penelec have variable interests in the entities or the entities are
governmental or not-for-profit organizations not within the scope of FIN 46R.
JCP&L, Met-Ed or Penelec may hold variable interests in the remaining nine
entities, which sell their output at variable prices that correlate to some
extent with the operating costs of the plants.





As required by FIN
46R, FirstEnergy periodically requests from these nine entities the information
necessary to determine whether they are VIEs or whether JCP&L, Met-Ed or
Penelec is the primary beneficiary. FirstEnergy has been unable to obtain the
requested information, which in most cases was deemed by the requested entity to
be proprietary. As such, FirstEnergy applied the scope exception that exempts
enterprises unable to obtain the necessary information to evaluate entities
under FIN 46R. The maximum exposure to loss from these entities results from
increases in the variable pricing component under the contract terms and cannot
be determined without the requested data. Purchased power costs from these
entities during the first quarters of 2005 and 2004 are shown in the table
below:





6








**Three
      Months Ended****March
      31,****2005**
    
    **2004*****(In
      millions)***JCP&L
    
    $
    27
    
    $
    28Met-Ed
    
    
    16
    
    
    16Penelec
    
    
    7
    
    
    7$
    50
    
    $
    51





**Securitized
Transition Bonds**


The consolidated
financial statements of FirstEnergy and JCP&L include the results of
JCP&L Transition, a wholly owned limited liability company of JCP&L. In
June 2002, JCP&L Transition sold $320 million of transition bonds to
securitize the recovery of JCP&L's bondable stranded costs associated with
the previously divested Oyster Creek Nuclear Generating Station.


JCP&L did not
purchase and does not own any of the transition bonds, which are included as
long-term debt on FirstEnergy's and JCP&L's Consolidated Balance Sheets. The
transition bonds are obligations of JCP&L Transition only and are
collateralized solely by the equity and assets of JCP&L Transition, which
consist primarily of bondable transition property. The bondable transition
property is solely the property of JCP&L Transition.





Bondable transition
property represents the irrevocable right under New Jersey law of a utility
company to charge, collect and receive from its customers, through a
non-bypassable TBC, the principal amount and interest on the transition bonds
and other fees and expenses associated with their issuance. JCP&L sold the
bondable transition property to JCP&L Transition and, as servicer, manages
and administers the bondable transition property, including the billing,
collection and remittance of the TBC, pursuant to a servicing agreement with
JCP&L Transition. JCP&L is entitled to a quarterly servicing fee of
$100,000 that is payable from TBC collections.





**12. -
COMMITMENTS, GUARANTEES AND CONTINGENCIES:**





**(A)**  **GUARANTEES
AND OTHER ASSURANCES**





As part of normal
business activities, FirstEnergy enters into various agreements on behalf of its
subsidiaries to provide financial or performance assurances to third parties.
Such agreements include contract guarantees, surety bonds and ratings contingent
collateralization provisions. As of March 31, 2005, outstanding guarantees
and other assurances aggregated approximately $2.4 billion and included contract
guarantees ($1.0 billion), surety bonds ($0.3 billion) and LOC ($1.1
billion).





FirstEnergy
guarantees energy and energy-related payments of its subsidiaries involved in
energy commodity activities - principally to facilitate normal physical
transactions involving electricity, gas, emission allowances and coal.
FirstEnergy also provides guarantees to various providers of subsidiary
financing principally for the acquisition of property, plant and equipment.
These agreements legally obligate FirstEnergy to fulfill the obligations of
those subsidiaries directly involved in energy and energy-related transactions
or financing where the law might otherwise limit the counterparties' claims. If
demands of a counterparty were to exceed the ability of a subsidiary to satisfy
existing obligations, FirstEnergy's guarantee enables the counterparty's legal
claim to be satisfied by other FirstEnergy assets. The likelihood is remote that
such parental guarantees of $0.9 billion (included in the $1.0 billion discussed
above) as of March 31, 2005 will increase amounts otherwise to be paid by
FirstEnergy to meet its obligations incurred in connection with financings and
ongoing energy and energy-related contracts.





7








While these types of
guarantees are normally parental commitments for the future payment of
subsidiary obligations, subsequent to the occurrence of a credit
rating-downgrade or “material adverse
event” the immediate posting of cash
collateral or provision of an LOC may be required of the subsidiary. The
following table summarizes collateral provisions in effect as of March 31,
2005:





**Collateral
      Paid**
    
    **Remaining****Collateral
      Provisions**
    
    **Exposure**
    
    **Cash**
    
    **LOC**
    
    **Exposure(1)*****(In
      millions)***Credit rating
      downgrade
    
    $
    364
    
    $
    153
    
    $
    18
    
    $
    193Adverse
      Event
    
    
    42
    
    
    --
    
    
    8
    
    
    34Total
    
    $
    406
    
    $
    153
    
    $
    26
    
    $
    227





(1)
    As of May 2,
      2005, FirstEnergy’s total exposure decreased to $357 million and the
      remaining exposure decreased
      to $183
      million - net of $148 million of cash collateral and $26 million of LOC
      collateral provided by counterparties.




Most of
FirstEnergy's surety bonds are backed by various indemnities common within the
insurance industry. Surety bonds and related FirstEnergy guarantees of $267
million provide additional assurance to outside parties that contractual and
statutory obligations will be met in a number of areas including construction
jobs, environmental commitments and various retail transactions.


FirstEnergy has
guaranteed the obligations of the operators of the TEBSA project, up to a
maximum of $6 million (subject to escalation) under the project's operations and
maintenance agreement. In connection with the sale of TEBSA in January 2004, the
purchaser indemnified FirstEnergy against any loss under this guarantee.
FirstEnergy has also provided an LOC (currently at $47 million), which is
renewable and declines yearly based upon the senior outstanding debt of TEBSA.





**(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 FirstEnergy's earnings and competitive position. These environmental
regulations affect FirstEnergy's earnings and competitive position to the extent
that it competes with companies that are not subject to such regulations and
therefore do not bear the risk of costs associated with compliance, or failure
to comply, with such regulations. Overall, FirstEnergy believes it is in
compliance with existing regulations but is unable to predict future change in
regulatory policies and what, if any, the effects of such change would be.
FirstEnergy estimates additional capital expenditures for environmental
compliance of approximately $430 million for 2005 through 2007.


The Companies accrue
environmental liabilities only when they conclude that it is probable that they
have an obligation for such costs and can reasonably determine the amount of
such costs. Unasserted claims are reflected in the Companies’ determination of
environmental liabilities and are accrued in the period that they are both
probable and reasonably estimable.


*Clean Air Act
Compliance*


The Companies are
required to meet federally approved SO 2 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
SO 2 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 SO 2 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. NO x 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 NO x reductions from the
Companies' facilities. The EPA's NO x Transport Rule
imposes uniform reductions of NO x emissions (an
approximate 85 percent reduction in utility plant NO x emissions from
projected 2007 emissions) across a region of nineteen states (including
Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based
on a conclusion that such NO x emissions are
contributing significantly to ozone levels in the eastern United States. The
Companies believe their facilities are also complying with the NO x budgets established
under State Implementation Plans through combustion controls and post-combustion
controls, including Selective Catalytic Reduction and Selective Non-Catalytic
Reduction systems, and/or using emission allowances.





8





*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 March 10, 2005, the EPA finalized the "Clean Air
Interstate Rule" covering a total of 28 states (including Michigan, New Jersey,
Ohio and Pennsylvania) and the District of Columbia based on proposed findings
that air emissions from 28 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. CAIR will require additional
reductions of NO x and SO 2 emissions in two
phases (Phase I in 2009 for NOx, 2010 for SO 2 and Phase II in
2015 for both NOx and SO 2 ). The Companies’
Michigan, Ohio and Pennsylvania fossil-fired generation facilities will be
subject to the caps on SO 2 and NOx emissions,
whereas our New Jersey fossil-fired generation facilities will be subject to a
cap on NO x emissions only.
According to the EPA, SO 2 emissions will be
reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule,
with reductions reaching 73% (from 2003 levels) by 2015, capping SO 2 emissions in
affected states to just 2.5 million tons annually. NO x emissions will be
reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule,
with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional
NO x cap of 1.3 million
tons annually. The future cost of compliance with these regulations may be
substantial and will depend on 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 March 14, 2005, the EPA
finalized a cap-and-trade program to reduce mercury emissions in two phases from
coal-fired power plants. Initially, mercury emissions will decline by 2010 as a
"co-benefit" from implementation of SO 2 and NO x emission caps under
the EPA's CAIR program. Phase II of the mercury cap-and-trade program will cap
nationwide mercury emissions from coal-fired power plants at 15 tons per year by
2018. 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 (DOJ) 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. On March 18, 2005, OE and
Penn announced that they had reached a settlement with the EPA, the DOJ and
three states (Connecticut, New Jersey, and New York) that resolved all issues
related to the W. H. Sammis Plant New Source Review litigation. This settlement
agreement, which is in the form of a Consent Decree subject to a thirty-day
public comment period that ended on April 29, 2005 and final approval by the
District Court Judge, requires OE and Penn to reduce emissions from the W. H.
Sammis Plant and other plants through the installation of pollution control
devices requiring capital expenditures currently estimated to be $1.1 billion
(primarily in the 2008 to 2011 time period). The settlement agreement also
requires OE and Penn to spend up to $25 million towards environmentally
beneficial projects, which include wind energy purchase power agreements over a
20-year term. OE and Penn also agreed to pay a civil penalty of $8.5 million.
Results for the first quarter of 2005 include the penalties payable by OE and
Penn of $7.8 million and $0.7 million, respectively. OE and Penn also accrued
$9.2 million and $0.8 million, respectively, for cash contributions toward
environmentally beneficial projects during the first quarter of
2005.





*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 percent through
2012.
 The Companies cannot
currently estimate the financial impact of climate change policies, although the
potential restrictions on CO 2 emissions could
require significant capital and other expenditures. However, the CO 2 emissions per
kilowatt-hour of electricity generated by the Companies is lower than many
regional competitors due to the Companies' diversified generation sources which
include low or non-CO 2 emitting gas-fired
and nuclear generators.





9




FirstEnergy plans to
issue a report that will disclose the Companies’ environmental activities,
including their plans to respond to environmental requirements. FirstEnergy
expects to complete the report by December 1, 2005.





*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,
New Jersey and Pennsylvania have water quality standards applicable to the
Companies' operations. As provided in the Clean Water Act, authority to grant
federal National Pollutant Discharge Elimination System water discharge permits
can be assumed by a state. Ohio, New Jersey and Pennsylvania have assumed such
authority.


On September 7,
2004, the EPA established new performance standards under Section 316(b) of the
Clean Water Act 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.





*Regulation of
Hazardous Waste*


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


The Companies have
been named as PRPs at waste disposal sites, which may require cleanup under the
Comprehensive Environmental Response, Compensation, and Liability Act of 1980.
Allegations of disposal of hazardous substances at historical sites and the
liability involved are often unsubstantiated and subject to dispute; however,
federal law provides that all PRPs for a particular site are liable on a joint
and several basis. Therefore, environmental liabilities that are considered
probable have been recognized on the Consolidated Balance Sheet as of
March 31, 2005, based on estimates of the total costs of cleanup, the
Companies' proportionate responsibility for such costs and the financial ability
of other nonaffiliated entities to pay. In addition, JCP&L has accrued
liabilities for environmental remediation of former manufactured gas plants in
New Jersey; those costs are being recovered by JCP&L through a
non-bypassable SBC. Included in Current Liabilities and Other Noncurrent
Liabilities are accrued liabilities aggregating approximately $65 million
(JCP&L - $46.8 million, CEI - $2.3 million, TE - $0.2 million, Met-Ed -
$48,000 and other - $15.2 million) as of March 31, 2005.





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





*Power Outages
and Related Litigation*


In July 1999, the
Mid-Atlantic States experienced a severe heat wave, which resulted in power
outages throughout the service territories of many electric utilities, including
JCP&L's territory. In an investigation into the causes of the outages and
the reliability of the transmission and distribution systems of all four of New
Jersey’s electric utilities, the NJBPU concluded that there was not a prima
facie case demonstrating that, overall, JCP&L provided unsafe, inadequate or
improper service to its customers. Two class action lawsuits (subsequently
consolidated into a single proceeding) were filed in New Jersey Superior Court
in July 1999 against JCP&L, GPU and other GPU companies, seeking
compensatory and punitive damages arising from the July 1999 service
interruptions in the JCP&L territory.


10




In August 2002, the
trial court granted partial summary judgment to JCP&L and dismissed the
plaintiffs' claims for consumer fraud, common law fraud, negligent
misrepresentation, and strict product liability. In November 2003, the trial
court granted JCP&L's motion to decertify the class and denied plaintiffs'
motion to permit into evidence their class-wide damage model indicating damages
in excess of $50 million. These class decertification and damage rulings were
appealed to the Appellate Division. The Appellate Court issued a decision on
July 8, 2004, affirming the decertification of the originally certified
class, but remanding for certification of a class limited to those customers
directly impacted by the outages of transformers in Red Bank, New Jersey. On
September 8, 2004, the New Jersey Supreme Court denied the motions filed by
plaintiffs and JCP&L for leave to appeal the decision of the Appellate
Court. JCP&L has filed a motion for summary judgment. FirstEnergy is unable
to predict the outcome of these matters and no liability has been accrued as of
March 31, 2005.





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. The U.S. - Canada Power System Outage Task Force’s
final report in April 2004 on the outages 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 contained 46 “recommendations to prevent or minimize the scope
of future blackouts.” Forty-five of those
recommendations related to broad industry or policy matters while one, including
subparts, related to activities the Task Force recommended be undertaken by
FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the
August 14, 2003 power outages. FirstEnergy implemented several initiatives,
both prior to and since the August 14, 2003 power outages, which were
independently verified by NERC as complete in 2004 and were consistent with
these and other recommendations and collectively enhance the reliability of its
electric system. 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 completed in 2004 had a material effect on its continuing 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 March 31, 2005 for any expenditures in excess of
those actually incurred through that date.





Three substantially
similar actions were filed in various Ohio State courts by plaintiffs seeking to
represent customers who allegedly suffered damages as a result of the
August 14, 2003 power outages. All three cases were dismissed for lack of
jurisdiction. One case was refiled on January 12, 2004 at the PUCO. The other
two cases were appealed. One case was dismissed and no further appeal was
sought. In the remaining case, the Court of Appeals on March 31, 2005
affirmed the trial court’s decision dismissing the case. It is not yet known
whether further appeal will be sought. 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 was
filed on August 25, 2004 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.





11





*Nuclear Plant
Matters*


FENOC received a
subpoena in late 2003 from a grand jury sitting in the United States District
Court for the Northern District of Ohio, Eastern Division requesting the
production of certain documents and records relating to the inspection and
maintenance of the reactor vessel head at the Davis-Besse Nuclear Power Station.
On December 10, 2004, FirstEnergy received a letter from the United States
Attorney's Office stating that FENOC is a target of the federal grand jury
investigation into alleged false statements made to the NRC in the Fall of 2001
in response to NRC Bulletin 2001-01. The letter also said that the designation
of FENOC as a target indicates that, in the view of the prosecutors assigned to
the matter, it is likely that federal charges will be returned against FENOC by
the grand jury. On February 10, 2005, FENOC received an additional subpoena
for documents related to root cause reports regarding reactor head degradation
and the assessment of reactor head management issues at
Davis-Besse.


On April 21,
2005, the NRC issued a NOV and proposed a $5.45 million civil penalty related to
the degradation of the Davis-Besse reactor vessel head described above. Under
the NRC’s letter, FENOC has ninety days to respond to this NOV.
FirstEnergy accrued the remaining liability for the proposed fine of $3.45
million during the first quarter of 2005.





If it were ultimately determined that FirstEnergy or its subsidiaries has
legal liability based on the Davis-Besse head degradation, it could have a
material adverse effect on FirstEnergy's or its subsidiaries' financial
condition and results of operations.





On August 12,
2004, the NRC notified FENOC that it would 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,
which is owned and/or leased by OE, CEI, TE and Penn. On April 4,
2005, the NRC held a public forum to discuss FENOC’s performance at the Perry
Nuclear Power Plant as identified in the NRC's annual assessment letter to
FENOC. Similar public meetings are held with all nuclear power plant licensees
following issuance by the NRC of their annual assessments. According to the NRC,
overall the Perry Plant operated "in a manner that preserved public health and
safety" and met all cornerstone objectives although it remained under the
heightened NRC oversight since August 2004. During the public forum and in the
annual assessment, the NRC indicated that additional inspections will continue
and that the plant must improve performance to be removed from the
Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix. If
performance does not improve, the NRC has a range of options under the Reactor
Oversight Process from increased oversight to possible impact to the plant’s
operating authority. As a result, these matters could have a material adverse
effect on FirstEnergy's or its subsidiaries' financial condition.





*Other Legal
Matters*




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





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 Ohio Companies, and the Davis-Besse extended outage, have
become the subject of a formal order of investigation. The SEC's formal order of
investigation also encompasses issues raised during the SEC's examination of
FirstEnergy and the Companies under the PUHCA. Concurrent with this
notification, FirstEnergy received a subpoena asking for background documents
and documents related to the restatements and Davis-Besse issues. On
December 30, 2004, FirstEnergy received a second subpoena asking for
documents relating to issues raised during the SEC's PUHCA examination.
FirstEnergy has cooperated fully with the informal inquiry and will continue to
do so with the formal investigation.





If it were
ultimately determined that FirstEnergy or its subsidiaries have legal liability
or are otherwise made subject to liability based on the above matter, it could
have a material adverse effect on FirstEnergy's or its subsidiaries' financial
condition and results of operations.





12





**13. -
REGULATORY MATTERS:**





**Reliability
Initiatives**




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. 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.
On July 14, 2004, NERC independently verified that FirstEnergy had implemented
the various initiatives to be completed by June 30 or summer 2004, with minor
exceptions noted by FirstEnergy, which exceptions are now essentially complete.
FirstEnergy is proceeding with the implementation of the recommendations that
were to be completed subsequent to 2004 and will continue to periodically assess
the FERC-ordered Reliability Study recommendations for forecasted 2009 system
conditions, recognizing revised load forecasts and other changing system
conditions which may impact the recommendations. Thus far, implementation of the
recommendations has not required, nor is expected to require, substantial
investment in new, or material upgrades, to existing equipment. FirstEnergy
notes, however, that FERC or other applicable government agencies and
reliability coordinators may take a different view as to recommended
enhancements or may recommend additional enhancements in the future that could
require additional, material expenditures. Finally, the PUCO is continuing to
review the FirstEnergy filing that addressed upgrades to control room computer
hardware and software and enhancements to the training of control room
operators, before determining the next steps, if any, in the proceeding.





As a result of
outages experienced in JCP&L's service area in 2002 and 2003, the NJBPU had
implemented reviews into JCP&L's service reliability. On March 29,
2004, the NJBPU adopted a Memorandum of Understanding (MOU) that set out
specific tasks related to service reliability to be performed by JCP&L and a
timetable for completion and endorsed JCP&L's ongoing actions to implement
the MOU. On June 9, 2004, the NJBPU approved a stipulation that
incorporates the final report of a Special Reliability Master who made
recommendations on appropriate courses of action necessary to ensure system-wide
reliability. The stipulation also incorporates the Executive Summary and
Recommendation portions of the final report of a focused audit of JCP&L's
Planning and Operations and Maintenance programs and practices (Focused Audit).
A final order in the Focused Audit docket was issued by the NJBPU on
July 23, 2004. On February 11, 2005, JCP&L met with the Ratepayer
Advocate to discuss reliability improvements. JCP&L continues to file
compliance reports reflecting activities associated with the MOU and
Stipulation.





In May 2004, the
PPUC issued an order approving revised reliability benchmarks 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, 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.





In November 2004, the PPUC approved a settlement agreement filed by Met-Ed,
Penelec and Penn that addressed issues related to a PPUC investigation into
Met-Ed's, Penelec's and Penn's service reliability performance. 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.





**Ohio**





On August 5,
2004, the Ohio Companies accepted the Rate Stabilization Plan as modified and
approved by the PUCO on August 4, 2004, subject to a competitive bid
process. The Rate Stabilization Plan was filed by the Ohio Companies to
establish generation service rates beginning January 1, 2006, in response
to PUCO concerns about price and supply uncertainty following the end of the
Ohio Companies' transition plan market development period. In the second quarter
of 2004, the Ohio Companies implemented the accounting modifications related to
the extended amortization periods and interest costs deferral on the deferred
customer shopping incentive balances. On October 1 and October 4,
2004, the OCC and NOAC, respectively, filed appeals with the Supreme Court of
Ohio to overturn the June 9, 2004 PUCO order and associated entries on
rehearing.





The revised Rate
Stabilization Plan extends current generation prices through 2008, ensuring
adequate generation supply at stabilized prices, and continues the Ohio
Companies' support of energy efficiency and economic development efforts. Other
key components of the revised Rate Stabilization Plan include the
following:


·
    extension of
      the transition cost amortization period for OE from 2006 to as late as
      2007; for CEI from 2008 to as late as mid-2009 and for TE from mid-2007 to
      as late as mid-2008;
  13


·
    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 require the Ohio Companies to undertake, no more often than annually, a
similar competitive bid process to secure generation for the years 2007 and
2008. Any acceptance of future competitive bid results would terminate the Rate
Stabilization Plan pricing, but not the related approved accounting, and not
until twelve months after the PUCO authorizes such termination.





**New
Jersey**





JCP&L is
permitted to defer for future collection from customers the amounts by which its
costs of supplying BGS to non-shopping customers and costs incurred under NUG
agreements exceed amounts collected through BGS and MTC rates. As of
March 31, 2005, the accumulated deferred cost balance totaled approximately
$472 million. New Jersey law allows for securitization of JCP&L's deferred
balance upon application by JCP&L and a determination by the NJBPU that the
conditions of the New Jersey restructuring legislation are met. On
February 14, 2003, JCP&L filed for approval of the securitization of
the deferred balance. There can be no assurance as to the extent, if any, that
the NJBPU will permit such securitization.





The July 2003 NJBPU decision on JCP&L's base electric rate proceeding
disallowed certain regulatory assets. JCP&L recorded charges to net income
in 2003 for the disallowed costs aggregating $185 million ($109 net of tax). The
subsequent NJBPU final decision and order issued in May  2004 resulted in
JCP&L recording a $5.4 million reduction in 2004 of the estimated charges in
2003. The 2003 NJBPU decision also provided for an interim return on
equity of 9.5% on JCP&L's rate base. The decision ordered a Phase II
proceeding to review whether JCP&L is in compliance with current service
reliability and quality standards. The NJBPU also ordered that any expenditures
and projects undertaken by JCP&L to increase its system's reliability be
reviewed as part of the Phase II proceeding, to determine their prudence and
reasonableness for rate recovery. In that Phase II proceeding, the NJBPU could
increase JCP&L’s return on equity to 9.75% or decrease it to 9.25%,
depending on its assessment of the reliability of JCP&L's service. Any
reduction would be retroactive to August 1, 2003. JCP&L filed an
August 15, 2003 interim motion for rehearing and reconsideration with the
NJBPU and a June 1, 2004 supplemental and amended motion for rehearing and
reconsideration. On July 7, 2004, the NJBPU granted limited reconsideration
and rehearing on the following issues: (1) deferred cost disallowances; (2) the
capital structure including the rate of return; (3) merger savings, including
amortization of costs to achieve merger savings; and (4) decommissioning costs.
Management is unable to predict when a decision may be reached by the
NJBPU.





On July 16,
2004, JCP&L filed the Phase II petition and testimony with the NJBPU,
requesting an increase in base rates of $36 million for the recovery of system
reliability costs and a 9.75% return on equity. The filing also requests an
increase to the MTC deferred balance recovery of approximately $20 million
annually. The Ratepayer Advocate filed testimony on November 16, 2004, and
JCP&L submitted rebuttal testimony on January 4, 2005. The Ratepayer
Advocate surrebuttal testimony was submitted February 8, 2005. Discovery
and settlement conferences are ongoing.


JCP&L sells all
self-supplied energy (NUGs and owned generation) to the wholesale market with
offsetting credits to its deferred energy balance with the exception of 300 MW
from JCP&L's NUG committed supply currently being used to serve BGS
customers pursuant to NJBPU order. New BGS tariffs reflecting the results of a
February 2004 auction for the BGS supply became effective June 1, 2004. The
auction for the supply period beginning June 1, 2005 was completed in
February 2005. The NJBPU decision on the BGS post transition year three process
was announced on October 22, 2004, approving with minor modifications the
BGS procurement process filed by JCP&L and the other New Jersey electric
distribution companies and authorizing the continued use of NUG committed supply
to serve 300 MW of BGS load.





In accordance with
an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7,
2004 supporting a continuation of the current level and duration of the funding
of TMI-2 decommissioning costs by New Jersey customers without a reduction,
termination or capping of the funding. On September 30, 2004, JCP&L
filed an updated TMI-2 decommissioning study. This study resulted in an updated
total decommissioning cost estimate of $729 million (in 2003 dollars) compared
to the estimated $528 million (in 2003 dollars) from the prior 1995
decommissioning study. The Ratepayer Advocate filed comments on
February 28, 2005. On March 18, 2005, JCP&L filed a response to
those comments. A schedule for further proceedings has not yet been
set.





14





**Pennsylvania**





A February 2002
Commonwealth Court of Pennsylvania decision affirmed the June 2001 PPUC decision
regarding approval of the FirstEnergy/GPU merger, remanded the issues of
quantification and allocation of merger savings to the PPUC and denied Met-Ed
and Penelec the rate relief initially approved in the PPUC decision. In October
2003, the PPUC issued an order concluding that the Commonwealth Court reversed
the PPUC’s June 2001 order in its entirety. In accordance with the PPUC's
direction, Met-Ed and Penelec filed supplements to their tariffs that were
effective October 2003 and that reflected the CTC rates and shopping credits in
effect prior to the June 2001 order.





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





In response to their
October 8, 2003 petition, the PPUC approved June 30, 2004 as the date
for Met-Ed's and Penelec's NUG trust fund refunds. The PPUC denied the
accounting request regarding the CTC rate/shopping credit swap by requiring
Met-Ed and Penelec to treat the stipulated CTC rates that were in effect from
January 1, 2002 on a retroactive basis. Met-Ed and Penelec subsequently
filed with the Commonwealth Court, on October 31, 2003, an Application for
Clarification with the judge, a Petition for Review of the PPUC's October 2
and October 16 Orders, and an application for reargument if the judge, in
his clarification order, indicates that Met-Ed's and Penelec's Objection was
intended to be denied on the merits. The Reargument Brief before the
Commonwealth Court was filed January 28, 2005.




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





**Transmission**





On November 1,
2004, ATSI requested authority from the FERC to defer approximately $54 million
of vegetation management costs ($14 million deferred as of March 31, 2005)
estimated to be incurred from 2004 through 2007. On March 4, 2005, the FERC
approved ATSI's request to defer those costs. ATSI expects to file an
application with FERC in the first quarter of 2006 for recovery of the deferred
costs.





ATSI and MISO filed
with the FERC on December 2, 2004, seeking approval for ATSI to have
transmission rates established based on a FERC-approved cost of service -
formula rate included in Attachment O under the MISO tariff. The ATSI Network
Service net revenue requirement increased under the formula rate to
approximately $159 million. On January 28, 2005, the FERC accepted for
filing the revised tariff sheets to become effective February 1, 2005,
subject to refund, and ordered a public hearing be held to address the
reasonableness of the proposal to eliminate the voltage-differentiated rate
design for the ATSI zone. On April 4, 2005, a settlement with all parties
to the proceeding was filed with the FERC that provides for recovery of the full
amount of the rate increase permitted under the formula.





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





On January 12,
2005, Met-Ed and Penelec filed a request with the PPUC for deferral of
transmission-related costs beginning January 1, 2005, estimated to be
approximately $8 million per month.





Various parties have
intervened in each of the cases above, and the Companies have not yet
implemented deferral accounting for these costs.





15




On
September 16, 2004, the FERC issued an order that imposed additional
obligations on CEI under certain pre-Open Access transmission contracts among
CEI and the cities of Cleveland and Painesville, Ohio. Under the FERC's
decision, CEI may be responsible for a portion of new energy market charges
imposed by MISO when its energy markets begin in the spring of 2005. CEI filed
for rehearing of the order from the FERC on October 18, 2004. On
April 15, 2005, the FERC issued an order on rehearing that "carves out"
these contracts from the MISO Day 2 market. While the order on rehearing is
favorable to CEI, the impact of the FERC decision on CEI is dependent upon many
factors, including the arrangements made by the cities for transmission service
and MISO's ability to administer the contracts. Accordingly, the impact of this
decision cannot be determined at this time.





**Regulatory
Assets**





The EUOC recognize,
as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU have authorized
for recovery from customers in future periods. 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
regulatory 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.





The Ohio Companies
are deferring customer shopping incentives and interest costs as new regulatory
assets in accordance with the transition and rate stabilization plans. These
regulatory assets (OE - $250 million, CEI - $320 million, TE - $98 million, as
of March 31, 2005) 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. OE, TE and CEI expect to recover these
deferred customer shopping incentives by August 31, 2008,
September 30, 2008 and August 31, 2010, respectively.


Regulatory
transition costs as of March 31, 2005 for JCP&L, Met-Ed and Penelec are
approximately $2.3 billion, $0.7 billion and $0.2 billion, respectively.
Deferral of above-market costs from power supplied by NUGs to JCP&L are
approximately $1.3 billion and are being recovered through BGS and MTC revenues.
Met-Ed and Penelec have deferred above-market NUG costs totaling approximately
$0.5 billion and $0.2 billion, respectively. These costs are being recovered
through CTC revenues. The regulatory asset for above-market NUG costs and a
corresponding liability are adjusted to fair value at the end of each quarter.
Recovery of the remaining regulatory transition costs is expected to continue
under the provisions of the various regulatory proceedings for New Jersey and
Pennsylvania.
   **14. - NEW
ACCOUNTING STANDARDS AND INTERPRETATIONS**







*FIN 47, “Accounting for Conditional Asset Retirement
Obligations - an interpretation of FASB Statement No. 143”*





On March 30,
2005, the FASB issued this interpretation to clarify the scope and timing of
liability recognition for conditional asset retirement obligations. Under this
interpretation, companies are required to recognize a liability for the fair
value of an asset retirement obligation that is conditional on a future event,
if the fair value of the liability can be reasonably estimated. In instances
where there is insufficient information to estimate the liability, the
obligation is to be recognized in the first period in which sufficient
information becomes available to estimate its fair value. If the fair value
cannot be reasonably estimated, that fact and the reasons why must be disclosed.
This Interpretation is effective no later than the end of fiscal years ending
after December 15, 2005. FirstEnergy is currently evaluating the effect
this standard will have on its financial statements.





*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. FirstEnergy is currently evaluating this standard but does not
expect it to have a material impact on its financial statements.





16


**


*SFAS 123
(revised 2004), “Share-Based Payment”*





In December 2004,
the FASB issued this revision to SFAS 123, which requires expensing stock
options in the financial statements. Important to applying the new standard is
understanding how to (1) measure the fair value of stock-based compensation
awards and (2) recognize the related compensation cost for those awards. For an
award to qualify for equity classification, it must meet certain criteria in
SFAS 123(R). An award that does not meet those criteria will be classified as a
liability and remeasured each period. SFAS 123(R) retains SFAS 123's
requirements on accounting for income tax effects of stock-based compensation.
In April 2005, the SEC delayed the effective date of SFAS 123(R) to annual,
rather than interim, periods that begin after June 15, 2005. The SEC’s new
rule results in a six-month deferral for FirstEnergy and other companies with a
fiscal year beginning January 1. The Company will be applying modified
prospective application, without restatement of prior interim periods. Any
potential cumulative adjustments have not been determined. FirstEnergy uses the
Black-Scholes option-pricing model to value options and will continue to do so
upon adoption of SFAS 123(R).





*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 FirstEnergy after June 30, 2005. FirstEnergy is
currently evaluating this standard but does not expect it to have a material
impact on the financial statements.





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





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





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




Issued in December
2004, FSP 109-1 provides guidance related to the provision within the American
Jobs Creation Act of 2004 (Act) that provides a tax deduction on qualified
production activities. The Act includes a tax deduction of up to 9 percent (when
fully phased-in) of the lesser of (a) “qualified production activities income,” as defined in the Act, or (b) taxable income
(after the deduction for the utilization of any net operating loss
carryforwards). This tax deduction is limited to 50 percent of W-2 wages paid by
the taxpayer. The FASB believes that the deduction should be accounted for as a
special deduction in accordance with SFAS No. 109, “Accounting for Income Taxes.” FirstEnergy is currently evaluating this FSP but
does not expect it to have a material impact on the Company's financial
statements.
 
 **15. -
SEGMENT INFORMATION:**
 
 FirstEnergy has
three reportable segments: regulated services, power supply management services
(referred to as competitive electric energy services in previous filings) and
facilities (HVAC) services. The aggregate “Other”
segments do not individually meet the criteria to be considered a reportable
segment. FirstEnergy's primary segment is its regulated services segment, whose
operations include the regulated sale of electricity and distribution and
transmission services by its eight EUOC in Ohio, Pennsylvania and New Jersey.
The power supply management services segment primarily consists of the
subsidiaries (FES, FGCO and FENOC) that sell electricity in deregulated markets
and operate the generation facilities of OE, CEI, TE and Penn resulting from the
deregulation of the Companies' electric generation business. “Other”
consists of MYR (a construction service company); natural gas operations
(recently sold - see Note 6) and telecommunications services. The assets and
revenues for the other business operations are below the quantifiable threshold
for operating segments for separate disclosure as “reportable segments.”


17




The regulated
services segment designs, constructs, operates and maintains FirstEnergy's
regulated transmission and distribution systems. Its revenues are primarily
derived from electricity delivery and transition cost recovery. Assets of the
regulated services segment include generating units that are leased to the power
supply management services. The regulated services segment’s internal revenues
represent the rental revenues for the generating unit leases.





The power supply
management services segment has responsibility for FirstEnergy generation
operations. Its net income is primarily derived from all electric generation
sales revenues, which consist of generation services to regulated franchise
customers who have not chosen an alternative generation supplier, retail sales
in deregulated markets and all domestic unregulated electricity sales in the
retail and wholesale markets less the related costs of electricity generation
and sourcing of commodity requirements. Its net income also reflects the expense
of the intersegment generating unit leases discussed above and property tax
amounts related to those generating units.





Segment reporting
for interim periods in 2004 was reclassified to conform with the current year
business segment organization and operations emphasizing FirstEnergy's regulated
electric businesses and power supply management operations and the
reclassification of discontinued operations (see Note 6). A previous reportable
segment was the more expansive competitive services segment whose aggregate
operations consisted of FirstEnergy generation operations, natural gas commodity
sales, providing local and long-distance phone service and other competitive
energy-related businesses such as facilities services and construction service
(MYR). Management's focus is on its core electric business. This has resulted in
a change in performance review analysis from an aggregate view of all
competitive services operations to a focus on its power supply management
services operations. During FirstEnergy's periodic review of reportable segments
under SFAS 131, that change resulted in the revision of reportable segments to
the separate reporting of power supply management services and facilities
services and including all other competitive services operations in the "Other"
segment. Facilities services is being disclosed as a reporting segment due to
the subsidiaries qualifying as held for sale (see Note 6 for discussion of the
divestiture of two of its subsidiaries in 2005). Interest expense on holding
company debt and corporate support services revenues and expenses are included
in "Reconciling Items."








**Segment
Financial Information**


**Power****Supply****Regulated**
    
    **Management**
    
    **Facilities**
    
    **Reconciling****Services**
    
    **Services**
    
    **Services**
    
    **Other**
    
    **Adjustments**
    
    **Consolidated****Three
      Months Ended**
    
    ***(In
      millions)*****March
      31, 2005**External
      revenues
    
    $
    1,339
    
    $
    1,295
    
    $
    56
    
    $
    112
    
    $
    11
    
    $
    2,813Internal
      revenues
    
    
    78
    
    
    --
    
    
    --
    
    
    --
    
    
    (78
    )
    
    --Total
      revenues
    
    
    1,417
    
    
    1,295
    
    
    56
    
    
    112
    
    
    (67
    )
    
    2,813Depreciation
      and amortization
    
    
    377
    
    
    10
    
    
    --
    
    
    1
    
    
    6
    
    
    394Net interest
      charges
    
    
    98
    
    
    10
    
    
    --
    
    
    1
    
    
    62
    
    
    171Income
      taxes
    
    
    155
    
    
    (25
    )
    
    (3
    )
    
    10
    
    
    (16
    )
    
    121Income before
      discontinued operations
    
    
    223
    
    
    (36
    )
    
    (2
    )
    
    5
    
    
    (49
    )
    
    141Discontinued
      operations
    
    
    --
    
    
    --
    
    
    13
    
    
    6
    
    
    --
    
    
    19Net
      income
    
    
    223
    
    
    (36
    )
    
    11
    
    
    11
    
    
    (49
    )
    
    160Total
      assets
    
    
    28,540
    
    
    1,582
    
    
    83
    
    
    495
    
    
    561
    
    
    31,261Total
      goodwill
    
    
    5,947
    
    
    24
    
    
    --
    
    
    63
    
    
    --
    
    
    6,034Property
      additions
    
    
    141
    
    
    81
    
    
    1
    
    
    2
    
    
    4
    
    
    229**March
      31, 2004**External
      revenues
    
    $
    1,290
    
    $
    1,522
    
    $
    58
    
    $
    116
    
    $
    11
    
    $
    2,997Internal
      revenues
    
    
    79
    
    
    --
    
    
    --
    
    
    --
    
    
    (79
    )
    
    --Total
      revenues
    
    
    1,369
    
    
    1,522
    
    
    58
    
    
    116
    
    
    (68
    )
    
    2,997Depreciation
      and amortization
    
    
    393
    
    
    9
    
    
    1
    
    
    --
    
    
    9
    
    
    412Net interest
      charges
    
    
    105
    
    
    11
    
    
    --
    
    
    1
    
    
    54
    
    
    171Income
      taxes
    
    
    145
    
    
    (1
    )
    
    (1
    )
    
    3
    
    
    (31
    )
    
    115Income before
      discontinued operations
    
    
    213
    
    
    (2
    )
    
    (1
    )
    
    5
    
    
    (42
    )
    
    173Discontinued
      operations
    
    
    --
    
    
    --
    
    
    --
    
    
    1
    
    
    --
    
    
    1Net
      income
    
    
    213
    
    
    (2
    )
    
    (1
    )
    
    6
    
    
    (42
    )
    
    174Total
      assets
    
    
    29,336
    
    
    1,426
    
    
    167
    
    
    778
    
    
    878
    
    
    32,585Total
      goodwill
    
    
    5,981
    
    
    24
    
    
    37
    
    
    75
    
    
    --
    
    
    6,117Property
      additions
    
    
    91
    
    
    44
    
    
    1
    
    
    --
    
    
    2
    
    
    138


Reconciling
adjustments to segment operating results from internal management reporting to
consolidated external financial reporting primarily consist of interest expense
related to holding company debt, corporate support services revenues and
expenses, fuel marketing revenues, which are reflected as reductions to expenses
for internal management reporting purposes, and elimination of intersegment
transactions.





18





**FIRSTENERGY
      CORP.****CONSOLIDATED
      STATEMENTS OF INCOME****(Unaudited)******
    
    **Three
      Months Ended****March
      31,****2005**
    
    **2004*****(In
      thousands, except per share
      amounts)*****REVENUES:**Electric
      utilities
    
    
    
    
    $
    2,308,516
    
    $
    2,177,033Unregulated
      businesses (Note 2)
    
    
    
    
    
    504,196
    
    
    819,505Total
      revenues
    
    
    
    
    
    2,812,712
    
    
    2,996,538**EXPENSES:**Fuel and
      purchased power (Note 2)
    
    
    
    
    
    895,332
    
    
    1,134,326Other
      operating expenses
    
    
    
    
    
    905,388
    
    
    812,642Provision for
      depreciation
    
    
    
    
    
    142,632
    
    
    145,850Amortization
      of regulatory assets
    
    
    
    
    
    310,841
    
    
    310,202Deferral of
      new regulatory assets
    
    
    
    
    
    (59,507
    )
    
    (44,405
    )General
      taxes
    
    
    
    
    
    185,179
    
    
    178,990Total
      expenses
    
    
    
    
    
    2,379,865
    
    
    2,537,605**INCOME
      BEFORE INTEREST AND INCOME TAXES**
    
    
    
    
    
    432,847
    
    
    458,933**NET
      INTEREST CHARGES:**Interest
      expense
    
    
    
    
    
    164,657
    
    
    172,510Capitalized
      interest
    
    
    
    
    
    (255
    )
    
    (6,470
    )Subsidiaries’
      preferred stock dividends
    
    
    
    
    
    6,553
    
    
    5,281Net interest
      charges
    
    
    
    
    
    170,955
    
    
    171,321**INCOME
      TAXES**
    
    
    
    
    
    121,104
    
    
    115,086**INCOME
      BEFORE DISCONTINUED OPERATIONS**
    
    
    
    
    
    140,788
    
    
    172,526Discontinued
      operations (net of income taxes (benefit) of ($7,598,000)and
      $1,028,000, respectively) (Note 6)
    
    
    
    
    
    18,938
    
    
    1,473**NET
      INCOME**
    
    
    
    
    $
    159,726
    
    $
    173,999**BASIC
      EARNINGS PER SHARE OF COMMON STOCK:**Income before
      discontinued operations
    
    
    
    
    $
    0.43
    
    $
    0.53Discontinued
      operations (Note 6)
    
    
    
    
    
    0.06
    
    
    --Net
      income
    
    
    
    
    $
    0.49
    
    $
    0.53**WEIGHTED
      AVERAGE NUMBER OF BASIC SHARES OUTSTANDING**
    
    
    
    
    
    327,908
    
    
    327,057**DILUTED
      EARNINGS PER SHARE OF COMMON STOCK:**Income before
      discontinued operations
    
    
    
    
    $
    0.42
    
    $
    0.53Discontinued
      operations (Note 6)
    
    
    
    
    
    0.06
    
    
    --Net
      income
    
    
    
    
    $
    0.48
    
    $
    0.53**WEIGHTED
      AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING**
    
    
    
    
    
    329,427
    
    
    329,034**DIVIDENDS
      DECLARED PER SHARE OF COMMON STOCK**
    
    
    
    
    $
    0.4125
    
    $
    0.375The preceding
      Notes to Consolidated Financial Statements as they relate to FirstEnergy
      Corp. are an integral part of these
      statements.
     19
   **FIRSTENERGY
      CORP.****CONSOLIDATED
      STATEMENTS OF COMPREHENSIVE INCOME****(Unaudited)******
    
    **Three
      Months Ended****March
      31,****2005**
    
    
    
    **2004*****(In
      thousands)*****NET
      INCOME**
    
    
    
    
    $
    159,726
    
    
    
    
    $
    173,999**OTHER
      COMPREHENSIVE INCOME (LOSS):**Unrealized
      gain on derivative hedges
    
    
    
    
    
    7,323
    
    
    
    
    
    1,365Unrealized
      gain (loss) on available for sale securities
    
    
    
    
    
    (7,986
    )
    
    
    
    
    16,938Other
      comprehensive income
    
    
    
    
    
    (663
    )
    
    
    
    
    18,303Income tax
      related to other comprehensive income
    
    
    
    
    
    129
    
    
    
    
    
    (9,480
    )Other
      comprehensive income (loss), net of tax
    
    
    
    
    
    (534
    )
    
    
    
    
    8,823**COMPREHENSIVE
      INCOME**
    
    
    
    
    $
    159,192
    
    
    
    
    $
    182,822The preceding
      Notes to Consolidated Financial Statements as they relate to FirstEnergy
      Corp. are an integral part of these
      statements.
   20
  **FIRSTENERGY
      CORP.****CONSOLIDATED
      BALANCE SHEETS****(Unaudited)****March
      31,**
    
    **December
      31,****2005**
    
    **2004*****(In
      thousands)*****ASSETS****CURRENT
      ASSETS:**Cash and cash
      equivalents
    
    
    
    
    $
    81,191
    
    $
    52,941Receivables-Customers
      (less accumulated provisions of $31,457,000 and$34,476,000,
      respectively, for uncollectible accounts)
    
    
    
    
    
    983,488
    
    
    979,242Other (less
      accumulated provisions of $32,807,000 and$26,070,000,
      respectively, for uncollectible accounts)
    
    
    
    
    
    275,355
    
    
    377,195Materials and
      supplies, at average cost-Owned
    
    
    
    
    
    378,951
    
    
    363,547Under
      consignment
    
    
    
    
    
    98,917
    
    
    94,226Prepayments
      and other
    
    
    
    
    
    248,388
    
    
    145,1962,066,290
    
    
    2,012,347**PROPERTY,
      PLANT AND EQUIPMENT:**In
      service
    
    
    
    
    
    22,294,674
    
    
    22,213,218Less -
      Accumulated provision for depreciation
    
    
    
    
    
    9,479,701
    
    
    9,413,73012,814,973
    
    
    12,799,488Construction
      work in progress
    
    
    
    
    
    735,090
    
    
    678,86813,550,063
    
    
    13,478,356**INVESTMENTS:**Nuclear plant
      decommissioning trusts
    
    
    
    
    
    1,604,062
    
    
    1,582,588Investments in
      lease obligation bonds
    
    
    
    
    
    918,632
    
    
    951,352Other
    
    
    
    
    
    734,419
    
    
    740,0263,257,113
    
    
    3,273,966**DEFERRED
      CHARGES:**Regulatory
      assets
    
    
    
    
    
    5,606,433
    
    
    5,532,087Goodwill
    
    
    
    
    
    6,033,728
    
    
    6,050,277Other
    
    
    
    
    
    746,936
    
    
    720,91112,387,097
    
    
    12,303,275$
    31,260,563
    
    $
    31,067,944**LIABILITIES
      AND CAPITALIZATION****CURRENT
      LIABILITIES:**Currently
      payable long-term debt
    
    
    
    
    $
    960,168
    
    $
    940,944Short-term
      borrowings
    
    
    
    
    
    310,125
    
    
    170,489Accounts
      payable
    
    
    
    
    
    663,018
    
    
    610,589Accrued
      taxes
    
    
    
    
    
    687,341
    
    
    657,219Other
    
    
    
    
    
    1,022,302
    
    
    929,1943,642,954
    
    
    3,308,435**CAPITALIZATION:**Common
      stockholders’ equity-Common stock,
      $.10 par value, authorized 375,000,000 shares-329,836,276
      shares outstanding
    
    
    
    
    
    32,984
    
    
    32,984Other paid-in
      capital
    
    
    
    
    
    7,058,484
    
    
    7,055,676Accumulated
      other comprehensive loss
    
    
    
    
    
    (313,646
    )
    
    (313,112
    )Retained
      earnings
    
    
    
    
    
    1,881,047
    
    
    1,856,863Unallocated
      employee stock ownership plan common stock-1,821,553 and
      2,032,800 shares, respectively
    
    
    
    
    
    (37,916
    )
    
    (43,117
    )Total common
      stockholders' equity
    
    
    
    
    
    8,620,953
    
    
    8,589,294Preferred
      stock of consolidated subsidiaries
    
    
    
    
    
    238,719
    
    
    335,123Long-term debt
      and other long-term obligations
    
    
    
    
    
    9,719,893
    
    
    10,013,34918,579,565
    
    
    18,937,766**NONCURRENT
      LIABILITIES:**Accumulated
      deferred income taxes
    
    
    
    
    
    2,346,766
    
    
    2,324,097Asset
      retirement obligations
    
    
    
    
    
    1,095,105
    
    
    1,077,557Power purchase
      contract loss liability
    
    
    
    
    
    2,160,867
    
    
    2,001,006Retirement
      benefits
    
    
    
    
    
    1,255,077
    
    
    1,238,973Lease market
      valuation liability
    
    
    
    
    
    915,050
    
    
    936,200Other
    
    
    
    
    
    1,265,179
    
    
    1,243,9109,038,044
    
    
    8,821,743**COMMITMENTS,
      GUARANTEES AND CONTINGENCIES (Note 12)**$
    31,260,563
    
    $
    31,067,944The preceding
      Notes to Consolidated Financial Statements as they relate to FirstEnergy
      Corp. are an integral part of these balance
      sheets.
 21
   **FIRSTENERGY
      CORP.****CONSOLIDATED
      STATEMENTS OF CASH FLOWS****(Unaudited)******
    
    **Three
      Months Ended****March
      31,****2005**
    
    **2004*****(In
      thousands)*****CASH
      FLOWS FROM OPERATING ACTIVITIES:**Net
      income
    
    
    
    
    $
    159,726
    
    $
    173,999Adjustments to
      reconcile net income to net cash from operating
activities-Provision for
      depreciation
    
    
    
    
    
    142,632
    
    
    145,850Amortization
      of regulatory assets
    
    
    
    
    
    310,841
    
    
    310,202Deferral of
      new regulatory assets
    
    
    
    
    
    (59,507
    )
    
    (44,405
    )Nuclear fuel
      and lease amortization
    
    
    
    
    
    18,648
    
    
    21,874Other
      amortization, net
    
    
    
    
    
    (5,451
    )
    
    (4,723
    )Deferred
      purchased power and other costs
    
    
    
    
    
    (109,233
    )
    
    (83,907
    )Deferred
      income taxes and investment tax credits, net
    
    
    
    
    
    (14,156
    )
    
    5,923Deferred rents
      and lease market valuation liability
    
    
    
    
    
    (35,663
    )
    
    (16,297
    )Accrued
      retirement benefit obligations
    
    
    
    
    
    16,103
    
    
    24,636Accrued
      compensation, net
    
    
    
    
    
    (41,722
    )
    
    4,387Commodity
      derivative transactions, net
    
    
    
    
    
    187
    
    
    (30,787
    )Income from
      discontinued operations (Note 6)
    
    
    
    
    
    (18,938
    )
    
    (1,473
    )Decrease
      (Increase) in operating assets:Receivables
    
    
    
    
    
    90,663
    
    
    272,746Materials and
      supplies
    
    
    
    
    
    7,457
    
    
    21,580Prepayments
      and other current assets
    
    
    
    
    
    (106,122
    )
    
    (47,031
    )Increase
      (Decrease) in operating liabilities:Accounts
      payable
    
    
    
    
    
    61,419
    
    
    (177,018
    )Accrued
      taxes
    
    
    
    
    
    40,712
    
    
    30,902Accrued
      interest
    
    
    
    
    
    108,601
    
    
    86,281Other
    
    
    
    
    
    2,593
    
    
    (44,888
    )Net cash
      provided from operating activities
    
    
    
    
    
    568,790
    
    
    647,851**CASH
      FLOWS FROM FINANCING ACTIVITIES:**New
      Financing-Long-term
      debt
    
    
    
    
    
    --
    
    
    581,558Short-term
      borrowings, net
    
    
    
    
    
    139,811
    
    
    --Redemptions
      and Repayments-Preferred
      stock
    
    
    
    
    
    (97,900
    )
    
    --Long-term
      debt
    
    
    
    
    
    (235,888
    )
    
    (268,920
    )Short-term
      borrowings, net
    
    
    
    
    
    --
    
    
    (387,541
    )Net controlled
      disbursement activity
    
    
    
    
    
    (29,937
    )
    
    (42,656
    )Common stock
      dividend payments
    
    
    
    
    
    (135,306
    )
    
    (122,465
    )Net cash used
      for financing activities
    
    
    
    
    
    (359,220
    )
    
    (240,024
    )**CASH
      FLOWS FROM INVESTING ACTIVITIES:**Property
      additions
    
    
    
    
    
    (228,884
    )
    
    (138,406
    )Proceeds from
      asset sales
    
    
    
    
    
    53,724
    
    
    11,439Nonutility
      generation trust contributions
    
    
    
    
    
    --
    
    
    (50,614
    )Contributions
      to nuclear decommissioning trusts
    
    
    
    
    
    (25,370
    )
    
    (25,370
    )Cash
      investments
    
    
    
    
    
    26,904
    
    
    20,218Other
    
    
    
    
    
    (7,694
    )
    
    (58,800
    )Net cash used
      for investing activities
    
    
    
    
    
    (181,320
    )
    
    (241,533
    )Net increase
      in cash and cash equivalents
    
    
    
    
    
    28,250
    
    
    166,294Cash and cash
      equivalents at beginning of period
    
    
    
    
    
    52,941
    
    
    113,975Cash and cash
      equivalents at end of period
    
    
    
    
    $
    81,191
    
    $
    280,269The preceding
      Notes to Consolidated Financial Statements as they relate to FirstEnergy
      Corp. are an integral part of these
      statements.







22








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





























To the Stockholders
and Board of


Directors of
FirstEnergy Corp.:





We have reviewed the
accompanying consolidated balance sheet of FirstEnergy Corp. and its
subsidiaries as of March 31, 2005, and the related consolidated statements
of income, comprehensive income and cash flows for each of the three-month
periods ended March 31, 2005 and 2004. These interim financial statements
are the responsibility of the Company’s management.





We conducted our
review in accordance with the standards of the Public Company Accounting
Oversight Board (United States). A review of interim financial information
consists principally of applying analytical procedures and making inquiries of
persons responsible for financial and accounting matters. It is substantially
less in scope than an audit conducted in accordance with the standards of the
Public Company Accounting Oversight Board, the objective of which is the
expression of an opinion regarding the financial statements taken as a whole.
Accordingly, we do not express such an opinion.





Based on our review,
we are not aware of any material modifications that should be made to the
accompanying consolidated interim financial statements for them to be in
conformity with accounting principles generally accepted in the United States of
America.





We previously
audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheet as of
December 31, 2004, and the related consolidated statements of income,
capitalization, common stockholders’ equity, preferred stock, cash flows and
taxes for the year then ended, management’s assessment of the effectiveness of
the Company’s internal control over financial reporting as of December 31,
2004 and the effectiveness of the Company’s internal control over financial
reporting as of December 31, 2004; and in our report (which contained
references to the Company’s change in its method of accounting for asset
retirement obligations as of January 1, 2003 as discussed in Note 2(K) to
those consolidated financial statements and the Company’s change in its method
of accounting for the consolidation of variable interest entities as of
December 31, 2003 as discussed in Note 7 to those consolidated financial
statements) dated March 7, 2005, we expressed unqualified opinions thereon.
The consolidated financial statements and management’s assessment of the
effectiveness of internal control over financial reporting referred to above are
not presented herein. In our opinion, the information set forth in the
accompanying consolidated balance sheet information as of December 31,
2004, is fairly stated in all material respects in relation to the consolidated
balance sheet from which it has been derived.














PricewaterhouseCoopers
LLP


Cleveland,
Ohio


May 3,
2005











23





**FIRSTENERGY
CORP.**





**MANAGEMENT’S
DISCUSSION AND ANALYSIS OF**


**RESULTS OF
OPERATIONS AND FINANCIAL CONDITION**








**EXECUTIVE
SUMMARY**








Net income in the
first quarter of 2005 was $160 million, or basic earnings of $0.49 per share of
common stock ($0.48 diluted), compared to net income of $174 million, or basic
and diluted earnings of $0.53 per share of common stock for the first quarter of
2004. During the quarter, FirstEnergy continued to divest non-core assets,
including the sale of FirstEnergy’s retail natural gas business. These
activities resulted in a combined net gain for the quarter of $0.07 per share of
common stock.





The impact of costs
associated with FirstEnergy’s settlement of the W. H. Sammis New Source Review
(NSR) case and a proposed NRC fine related to the 2002 outage at the Davis-Besse
nuclear power plant reduced earnings for the quarter by $0.05 per share of
common stock. Also, nuclear operation and maintenance cost increases associated
with the scheduled outages at the Davis-Besse and Perry nuclear power plants,
combined with an unplanned outage at the Perry plant, reduced earnings per share
by $0.12 compared with the first quarter of 2004.





On March 18,
2005, FirstEnergy announced that it had reached a settlement with the U.S. EPA,
the U.S. Department of Justice, and three states that resolved all issues
related to various parties’ actions against FirstEnergy’s W. H. Sammis Plant in
the pending NSR case. The agreement, which is in the form of a consent decree,
also was signed by the states of Connecticut, New Jersey and New York and was
filed with the Court.





Under the agreement,
FirstEnergy will install environmental controls at all seven units of the Sammis
Plant, as well as at other power plants. FirstEnergy will also upgrade existing
scrubber systems on units 1 through 3 of its Bruce Mansfield Plant. Projects at
the Sammis Plant will include equipment designed to reduce 95 percent of
SO 2 emissions and 90
percent of NO x emissions on the
plant’s two largest units. Additionally, the plant’s five smaller units will be
controlled by equipment designed to reduce at least 50 percent of SO 2 and 70 percent of
NO x emissions. In
total, additional environmental controls could be installed on nearly 5,500 MW
of FirstEnergy’s 7,400 MW coal-based generating capacity, with construction
beginning in 2005 and completed no later than 2012. The estimated $1.1 billion
investment in environmental improvements is consistent with assumptions
reflected in the Companies’ long-term financial planning.





On March 15,
2005, members of the International Brotherhood of Electrical Workers System
Council U-3 ratified a new four-year contract with FirstEnergy subsidiary
JCP&L. Ratification of the contract resolved issues surrounding health care
and work rules, and ended a 14-week strike against JCP&L by the Council’s
members.





**FIRSTENERGY’S
BUSINESS**





FirstEnergy is a
registered public utility holding company headquartered in Akron, Ohio that
operates primarily through two core business segments.





·
    **Regulated
      Services**transmit,
      distribute and sell electric power through eight electric utility
      operating companies that collectively comprise the nation’s fifth largest
      investor-owned electric system, serving 4.4 million customers within
      36,100 square miles of Ohio, Pennsylvania and New Jersey. This business
      segment primarily derives its revenue from the delivery of electricity,
      including transition cost recovery.





·
    **Power
      Supply Management****Services**supplies the
      power needs of end-use customers (principally in Ohio, Pennsylvania and
      New Jersey) through retail and wholesale arrangements, including sales to
      meet the PLR requirements of FirstEnergy’s Ohio Companies and Penn. This
      business operates the generating facilities of the Ohio Companies and Penn
      and purchases from the wholesale market to meet its sales obligations. It
      leases fossil facilities from the EUOC and purchases the entire output of
      the EUOC nuclear plants. This business segment principally derives its
      revenues from electric generation sales.





Other operating
segments provide a wide range of services, including heating, ventilation,
air-conditioning, refrigeration, process piping, plumbing, electrical and
facility control systems, high-efficiency electrotechnologies and
telecommunication services. FirstEnergy continues to divest these non-core
businesses. See Note 6 to the consolidated financial statements.





24





**RESULTS OF
OPERATIONS**





The financial
results discussed below include revenues and expenses from transactions among
our business segments. A reconciliation of segment financial results is provided
in Note 15 to the consolidated financial statements. The FSG business segment is
included in "Other and Reconciling Adjustments" in this discussion due to its
immaterial impact on current period financial results, but is presented
separately in segment information provided in Note 15 to the consolidated
financial statements. Net income (loss) by major business segment was as
follow:





**Three
      Months Ended****March
      31,**
    
    **Increase****2005**
    
    **2004**
    
    **(Decrease)****Net
      Income (Loss)**
    
    ***(In
      millions)*****By
      Business Segment**Regulated
      services
    
    $
    223
    
    $
    213
    
    $
    10Power supply
      management services
    
    
    (36
    )
    
    (2
    )
    
    (34
    )Other and
      reconciling adjustments*
    
    
    (27
    )
    
    (37
    )
    
    10Total
    
    $
    160
    
    $
    174
    
    $
    (14
    )**Basic
      Earnings Per Share:**Income before
      discontinued operations
    
    $
    0.43
    
    $
    0.53
    
    $
    (0.10
    )Discontinued
      operations
    
    $
    0.06
    
    $
    --
    
    $
    0.06Net
      Income
    
    $
    0.49
    
    $
    0.53
    
    $
    (0.04
    )**Diluted
      Earnings Per Share:**Income before
      discontinued operations
    
    $
    0.42
    
    $
    0.53
    
    $
    (0.11
    )Discontinued
      operations
    
    $
    0.06
    
    $
    --
    
    $
    0.06Net
      Income
    
    $
    0.48
    
    $
    0.53
    
    $
    (0.05
    )





*
Represents other operating segments and reconciling items including interest
expense on holding company debt and corporate support


services revenues
and expenses.


Net income in the
first quarter of 2005 included after-tax earnings from discontinued operations
of $19 million ($0.06 per basic and diluted share) resulting from FirstEnergy’s
disposition of non-core assets and operations. In the first quarter of 2005,
discontinued operations included $17 million from net gains on sales (see “Other - First Quarter 2005 Compared to First
Quarter 2004” below) and $2 million from
operations. In the first quarter of 2004, net income included $1 million from
discontinued operations.
 
 A decrease in
wholesale electric revenues and purchased power costs in the first quarter of
2005 from the same period last year resulted from FES recording PJM sales and
purchased power transactions on an hourly net position basis beginning in the
first quarter of 2005 compared with recording each discrete transaction (on a
gross basis) in the same period of 2004. This change had no impact on earnings
and was caused by the dedication of FirstEnergy’s Beaver Valley Plant to PJM in
January 2005. FirstEnergy believes that this economic change required a net
presentation of revenues and purchased power transactions as these generation
assets are now dedicated in PJM where FirstEnergy has third-party customers.
Wholesale electric revenues and purchased power costs in the first quarter of
2004 each included $280 million of these transactions recorded on a gross
basis.
 
 Excluding the effect
of recording the wholesale electric revenue transactions in PJM on a gross basis
in 2004, first quarter 2005 operating revenues were modestly higher. Net income
declined primarily due to increased nuclear production costs from refueling
outages and the Sammis environmental settlement. Results for the first quarter
of 2005 were enhanced by reduced employee benefit costs (see “Postretirement Plans” below), gains on the sale of assets and reduced
fossil production costs.


25





Financial results
for FirstEnergy and its major business segments in the first quarter of 2005 and
2004 were as follows:








**Power****Supply**
    
    **Other
      and****1****st****Quarter 2005**
    
    **Regulated**
    
    **Management**
    
    **Reconciling**
    
    **FirstEnergy****Financial
      Results**
    
    **Services**
    
    **Services**
    
    **Adjustments**
    
    **Consolidated*****(In
      millions)***Revenue:ExternalElectric
    
    $
    1,162
    
    $
    1,275
    
    $
    --
    
    $
    2,437Other
    
    
    177
    
    
    20
    
    
    179
    
    
    376Internal
    
    
    78
    
    
    --
    
    
    (78
    )
    
    --Total
      Revenues
    
    
    1,417
    
    
    1,295
    
    
    101
    
    
    2,813Expenses:Fuel and
      purchased power
    
    
    --
    
    
    895
    
    
    --
    
    
    895Other
      operating
    
    
    418
    
    
    409
    
    
    79
    
    
    906Provision for
      depreciation
    
    
    126
    
    
    10
    
    
    7
    
    
    143Amortization
      of regulatory assets
    
    
    311
    
    
    --
    
    
    --
    
    
    311Deferral of
      new regulatory assets
    
    
    (60
    )
    
    --
    
    
    --
    
    
    (60
    )General
      taxes
    
    
    146
    
    
    32
    
    
    7
    
    
    185Total
      Expenses
    
    
    941
    
    
    1,346
    
    
    93
    
    
    2,380Net interest
      charges
    
    
    98
    
    
    10
    
    
    63
    
    
    171Income
      taxes
    
    
    155
    
    
    (25
    )
    
    (9
    )
    
    121Income before
      discontinued operations
    
    
    223
    
    
    (36
    )
    
    (46
    )
    
    141Discontinued
      operations
    
    
    --
    
    
    --
    
    
    19
    
    
    19Net
      Income
    
    $
    223
    
    $
    (36
    )
    $
    (27
    )
    $
    160











**Power****Supply**
    
    **Other
      and****1****st****Quarter 2004**
    
    **Regulated**
    
    **Management**
    
    **Reconciling**
    
    **FirstEnergy****Financial
      Results**
    
    **Services**
    
    **Services**
    
    **Adjustments**
    
    **Consolidated*****(In
      millions)***Revenue:ExternalElectric
    
    $
    1,154
    
    $
    1,502
    
    $
    --
    
    $
    2,656Other
    
    
    136
    
    
    20
    
    
    185
    
    
    341Internal
    
    
    79
    
    
    --
    
    
    (79
    )
    
    --Total
      Revenues
    
    
    1,369
    
    
    1,522
    
    
    106
    
    
    2,997Expenses:Fuel and
      purchased power
    
    
    --
    
    
    1,134
    
    
    --
    
    
    1,134Other
      operating
    
    
    366
    
    
    346
    
    
    101
    
    
    813Provision for
      depreciation
    
    
    127
    
    
    9
    
    
    10
    
    
    146Amortization
      of regulatory assets
    
    
    310
    
    
    --
    
    
    --
    
    
    310Deferral of
      new regulatory assets
    
    
    (44
    )
    
    --
    
    
    --
    
    
    (44
    )General
      taxes
    
    
    147
    
    
    25
    
    
    7
    
    
    179Total
      Expenses
    
    
    906
    
    
    1,514
    
    
    118
    
    
    2,538Net interest
      charges
    
    
    105
    
    
    11
    
    
    55
    
    
    171Income
      taxes
    
    
    145
    
    
    (1
    )
    
    (29
    )
    
    115Income before
      discontinued operations
    
    
    213
    
    
    (2
    )
    
    (38
    )
    
    173Discontinued
      operations
    
    
    --
    
    
    --
    
    
    1
    
    
    1Net
      Income
    
    $
    213
    
    $
    (2
    )
    $
    (37
    )
    $
    174








26








**Power****Change
      Between**
    
    
    
    **Supply**
    
    **Other
      and**
    
    **FirstEnergy****1****st****Quarter 2005 and 2004**
    
    **Regulated**
    
    **Management**
    
    **Reconciling**
    
    **Consolidated****Financial
      Results**
    
    **Services**
    
    **Services**
    
    **Adjustments**
    
    **Total****Increase
      (Decrease)**
    
    ***(In
      millions)***Revenue:ExternalElectric
    
    $
    8
    
    $
    (227
    )
    $
    --
    
    $
    (219
    )Other
    
    
    41
    
    
    --
    
    
    (6
    )
    
    35Internal
    
    
    (1
    )
    
    --
    
    
    1
    
    
    --Total
      Revenues
    
    
    48
    
    
    (227
    )
    
    (5
    )
    
    (184
    )Expenses:Fuel and
      purchased power
    
    
    --
    
    
    (239
    )
    
    --
    
    
    (239
    )Other
      operating
    
    
    52
    
    
    63
    
    
    (22
    )
    
    93Provision for
      depreciation
    
    
    (1
    )
    
    1
    
    
    (3
    )
    
    (3
    )Amortization
      of regulatory assets
    
    
    1
    
    
    --
    
    
    --
    
    
    1Deferral of
      new regulatory assets
    
    
    (16
    )
    
    --
    
    
    --
    
    
    (16
    )General
      taxes
    
    
    (1
    )
    
    7
    
    
    --
    
    
    6Total
      Expenses
    
    
    35
    
    
    (168
    )
    
    (25
    )
    
    (158
    )Net interest
      charges
    
    
    (7
    )
    
    (1
    )
    
    8
    
    
    --Income
      taxes
    
    
    10
    
    
    (24
    )
    
    20
    
    
    6Income before
      discontinued operations
    
    
    10
    
    
    (34
    )
    
    (8
    )
    
    (32
    )Discontinued
      operations
    
    
    --
    
    
    --
    
    
    18
    
    
    18Net
      Income
    
    $
    10
    
    $
    (34
    )
    $
    10
    
    $
    (14
    )








***Regulated
Services - First Quarter 2005 Compared to First Quarter
2004***





Net income increased to $223 million from $213 million (or 5%) in the first
quarter of 2005 with increased operating revenues partially offset by higher
operating expenses and taxes.





*Revenues
-*





The increase in
total revenues resulted from the following sources:








**Three
      Months Ended****Revenues**
    
    **March
      31,**
    
    **Increase****By
      Type of Service**
    
    **2005**
    
    **2004**
    
    **(Decrease)*****(In
      millions)***Distribution
      services
    
    $
    1,162
    
    $
    1,154
    
    $
    8Transmission
      services
    
    
    92
    
    
    62
    
    
    30Lease revenue
      from affiliates
    
    
    78
    
    
    79
    
    
    (1
    )Other
    
    
    85
    
    
    74
    
    
    11Total
      Revenues
    
    $
    1,417
    
    $
    1,369
    
    $
    48








Changes in
distribution deliveries by customer class are summarized in the following
table:








**Increase****Electric
      Distribution Deliveries**
    
    **(Decrease)**Residential
    
    
    (0.6
    )%Commercial
    
    
    4.7
    %Industrial
    
    
    4.3
    %Total
      Distribution Deliveries
    
    
    2.6
    %











27





Increased
consumption offset in part by lower prices resulted in higher distribution
delivery revenue. The following table summarizes major factors contributing to
the $8 million increase in distribution service revenue in the first quarter of
2005:








**Sources
      of Change****in
      Distribution Revenues****Increase
      (Decrease)**
    
    ***(In
      millions)***Changes in
      customer usage
    
    $
    23Changes in
      prices:Rate changes
      --Ohio shopping
      incentive
    
    
    (11
    )Other
    
    
    1Rate mix &
      other
    
    
    (5
    )Net Increase
      in Distribution Revenues
    
    $
    8







Transmission
revenues increased $30 million in the first quarter of 2005 from the same period
last year due in part to an amended power supply agreement with FES in June
2004. The amended agreement resulted in the regulated services segment assuming
certain transmission revenues and expenses that were previously attributed to
FES.


Other revenues
increased $11 million primarily due to a payment received under a contract
provision associated with the prior sale of TMI. Under the contract, additional
payments are received if subsequent energy prices rise above specified levels.
These payments are passed along to JCP&L, Met-Ed and Penelec customers,
resulting in no net earnings effect.





*Expenses-*





The higher revenues
discussed above were partially offset by the following increases in
expenses:





·
    Higher
      transmission expense of $43 million due in part to an amended power supply
      agreement with FES, which also increased revenue and other operating costs
      of $9 million; and





·
    Increased
      income taxes of $10 million due to increased taxable
    income.





Partially offsetting
these higher costs were two factors:





·
    Additional
      deferrals of regulatory assets of $16 million, primarily representing
      shopping incentives and interest on those deferrals;
and





·
    Lower interest
      charges of $7 million primarily due to debt and preferred stock
      redemptions.





***Power
Supply Management Services - First Quarter 2005 Compared to First Quarter
2004***





The net loss for
this segment increased to $36 million in the first quarter of 2005 from a net
loss of $2 million in the same period last year. An improvement in the gross
generation margin was more than offset by higher non-fuel nuclear costs,
resulting in the increased net loss.





*Generation
Margin -*





The gross generation
margin in the first quarter of 2005 improved by $12 million compared to the same
period of 2004, as shown in the table below.





**Gross
      Generation Margin**
    
    **2005**
    
    **2004**
    
    **Increase**
      **(Decrease)*****(In
      millions)***Electric
      generation revenue
    
    $
    1,275
    
    $
    1,502
    
    $
    (227
    )Fuel and
      purchased power costs
    
    
    895
    
    
    1,134
    
    
    (239
    )Gross
      Generation Margin
    
    $
    380
    
    $
    368
    
    $
    12





28





*Revenues
-*





Excluding the effect
of the change in recording PJM wholesale transactions, revenues increased $53
million in the first  quarter of 2005
compared to the same period of 2004 as a result of a 0.4% increase in KWH sales
and higher unit prices. Additional retail
sales reduced energy available for sales to the wholesale market.





A decrease in
reported segment revenues resulted from the following sources:








**Three
      Months Ended****Revenues**
    
    **March
      31,**
    
    **Increase****By
      Type of Service**
    
    **2005**
    
    **2004**
    
    **(Decrease)*****(In
      millions)***Electric
      Generation Sales:Retail
    
    $
    980
    
    $
    934
    
    $
    46Wholesale
    
    
    295
    
    
    288
    
    
    7Total Electric
      Generation Sales
    
    
    1,275
    
    
    1,222
    
    
    53Transmission
    
    
    10
    
    
    16
    
    
    (6
    )Other
    
    
    10
    
    
    4
    
    
    6Total
    
    
    1,295
    
    
    1,242
    
    
    53PJM gross
      transactions
    
    
    --
    
    
    280
    
    
    (280
    )Total
      Revenues
    
    $
    1,295
    
    $
    1,522
    
    $
    (227
    )








Changes in KWH sales
are summarized in the following table:








**Increase****Electric
      Generation**
    
    **(Decrease)**Retail
    
    
    1.2
    %Wholesale
    
    
    (49.4
    )%Total Electric
      Generation
    
    
    (15.9
    )%*





*  Increase of 0.4%
excluding the effect of the PJM revision.








*Expenses
-*




Excluding the effect
of the $280 million of PJM purchased power costs recorded on a gross basis in
2004, total operating expenses, net interest charges and income taxes increased
by $87 million. The increase was due to the following factors:





·
    Higher fuel
      and purchased power costs of $41 million, which include increased fuel
      costs of $34 million due to a greater reliance on higher cost fossil units
      during the nuclear refueling outages, and increased purchased power costs
      of $7 million;





·
    Increased
      non-fuel nuclear costs of $66 million due primarily to a refueling outage
      at the Perry nuclear plant (including an unplanned extension), a scheduled
      23-day mid-cycle inspection outage at the Davis-Besse nuclear plant in the
      first quarter of 2005 and the absence of nuclear scheduled outages in the
      same period last year;





·
    Accrual of an
      $8.5 million civil penalty payable to the Department of Justice and $10
      million for obligations to three states in connection with the Sammis
      Plant settlement;





·
    Accrual of
      $3.5 million for a proposed NRC fine related to the 2002 Davis-Besse
      outage; and





·
    Higher general
      taxes of $7 million due to additional gross receipts tax and payroll
      taxes.





29





Partially offsetting
these amounts were the following factors:





·
    Lower
      transmission costs of $26 million due in part to an amended power supply
      agreement that resulted in the regulated services segment assuming certain
      transmission obligations previously borne by the power supply management
      services segment; and





·
    Lower income
      taxes of $24 million due to lower taxable
income.





***Other -
First Quarter 2005 Compared to First Quarter 2004***


FirstEnergy’s
financial results from other operating segments and reconciling items, including
interest expense on holding company debt and corporate support services revenues
and expenses, resulted in a net improvement in FirstEnergy’s net income in the
first quarter of 2005 compared to the same quarter of 2004. The improvement
reflected the effect of discontinued operations, which included an after-tax net
gain of $17 million from discontinued operations (see Note 6). The following
table summarizes the sources of income from discontinued
operations:


***Other -
First Quarter 2005 Compared to First Quarter 2004***





**Three
      Months Ended****March
      31,****2005**
    
    **2004*****(In
      millions)***Discontinued
      Operations (Net of tax)Gain on
      sale:Natural gas
      business
    
    $
    5
    
    $
    --Elliot-Lewis,
      Spectrum and Power Piping
    
    
    12
    
    
    --Reclassification
      of operating income
    
    
    2
    
    
    1Total
    
    $
    19
    
    $
    1








***Postretirement
Plans***





Pension costs were
lower due to last year’s $500 million voluntary contribution and an increase in
the market value of pension plan assets during 2004. Combined with amendments to
FirstEnergy’s health care plan in the first quarter of 2004, employee benefit
expenses decreased by $20 million in the first quarter of 2005 compared to the
same period in 2004. The following table summarizes the net pension and OPEB
expense (excluding amounts capitalized) for the three months ended
March 31, 2005 and 2004.








**Three
      Months Ended****Postretirement
      Benefits Expense**(1)
    
    **March
      31,****2005**
    
    **2004*****(In
      millions*****)**Pension
    
    $
    8
    
    $
    20OPEB
    
    
    18
    
    
    26Total
    
    $
    26
    
    $
    46


(1)  Excludes the
capitalized portion of postretirement benefits
 costs (see Note 10
for total costs).








The decrease in
pension and OPEB expenses are included in various cost categories and have
contributed to other cost reductions discussed above.





**CAPITAL
RESOURCES AND LIQUIDITY**





FirstEnergy’s cash
requirements in 2005 for operating expenses, construction expenditures,
scheduled debt maturities and preferred stock redemptions are expected to be met
without increasing FirstEnergy’s net debt and preferred stock outstanding.
Available borrowing capacity under credit facilities will be used to manage
working capital requirements. Thereafter, FirstEnergy expects to use a
combination of cash from operations and funds from the capital
markets.





30





***Changes
in Cash Position***





The primary source
of ongoing cash for FirstEnergy, as a holding company, is cash dividends from
its subsidiaries. The holding company also has access to $1.375 billion of
revolving credit facilities. In the first quarter of 2005, FirstEnergy received
$137 million of cash dividends from its subsidiaries and paid $135 million in
cash dividends to its common shareholders. There are no material restrictions on
the payment of cash dividends by FirstEnergy’s subsidiaries.





As of March 31,
2005, FirstEnergy had $81 million of cash and cash equivalents ($3 million
restricted as an indemnity reserve) compared with $53 million as of
December 31, 2004. The major sources for changes in these balances are
summarized below.





***Cash
Flows From Operating Activities***




FirstEnergy's
consolidated net cash from operating activities is provided primarily by its
regulated and power supply businesses (see “RESULTS OF OPERATIONS” above). Net cash provided from operating
activities was $569 million in the first quarter of 2005 and $648 million in the
first quarter of 2004, summarized as follows:








**Three
      Months Ended****March
      31,****Operating
      Cash Flows**
    
    **2005**
    
    **2004*****(In
      millions)***Cash earnings(1)
    
    $
    364
    
    $
    505Working
      capital and other
    
    
    205
    
    
    143Total Cash
      Flows from Operating Activities
    
    $
    569
    
    $
    648





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







Cash earnings (in
the table above) are not a measure of performance calculated in accordance with
GAAP. FirstEnergy believes that cash earnings is a useful financial measure
because it provides investors and management with an additional means of
evaluating its cash-based operating performance. The following table reconciles
cash earnings with net income.








**Three
      Months Ended****March
      31,****Reconciliation
      of Cash Earnings**
    
    **2005**
    
    **2004*****(In
      millions)***Net Income
      (GAAP)
    
    $
    160
    
    $
    174Non-Cash
      Charges (Credits):Provision for
      depreciation
    
    
    143
    
    
    146Amortization
      of regulatory assets
    
    
    311
    
    
    310Deferral of
      new regulatory assets
    
    
    (60
    )
    
    (44
    )Nuclear fuel
      and lease amortization
    
    
    19
    
    
    22Deferred
      purchased power and other costs
    
    
    (109
    )
    
    (84
    )Deferred
      income taxes and investment tax credits
    
    
    (14
    )
    
    6Deferred rents
      and lease market valuation liability
    
    
    (36
    )
    
    (16
    )Income from
      discontinued operations
    
    
    (19
    )
    
    (1
    )Other non-cash
      expenses
    
    
    (31
    )
    
    (8
    )Cash Earnings
      (Non-GAAP)
    
    $
    364
    
    $
    505







The $141 million
decrease in cash earnings is described under "RESULTS OF OPERATIONS". The
working capital increase primarily resulted from changes of $238 million in
payables partially offset by a change of $182 million in
receivables.





31





**Cash Flows
From Financing Activities**





In the first
quarters of 2005 and 2004, net cash used for financing activities of $359
million and $240 million, respectively, primarily reflected the redemptions of
debt and preferred stock shown below.








**Three
      Months Ended****March
      31,****Securities
      Issued or Redeemed**
    
    **2005**
    
    **2004*****(In
      millions)****New
      Issues*Pollution
      control notes
    
    $
    --
    
    $
    185Senior
      notes
    
    
    --
    
    
    250Unsecured
      notes
    
    
    --
    
    
    147$
    --
    
    $
    582*Redemptions*First mortgage
      bonds
    
    $
    1
    
    $
    92Secured
      notes
    
    
    20
    
    
    42Long-term
      revolving credit
    
    
    215
    
    
    135Preferred
      stock
    
    
    98
    
    
    --$
    334
    
    $
    269Short-term
      Borrowings, Net
    
    $
    140
    
    $
    (388
    )






FirstEnergy had
approximately $310 million of short-term indebtedness as of March 31, 2005
compared to approximately $170 million as of December 31, 2004. Available
bank borrowing capability as of March 31, 2005 included the
following:








**Borrowing
      Capability**
    
    **FirstEnergy**
    
    **OE**
    
    **Penelec**
    
    **Total*****(In
      millions)***Long-term
      revolving credit
    
    $
    1,375
    
    $
    375
    
    $
    --
    
    $
    1,750Utilized
    
    
    --
    
    
    --
    
    
    --
    
    
    --Letters of
      credit
    
    
    (141
    )
    
    --
    
    
    --
    
    
    (141
    )Net
    
    
    1,234
    
    
    375
    
    
    --
    
    
    1,609Short-term
      bank facilities
    
    
    --
    
    
    34
    
    
    100
    
    
    134Utilized
    
    
    --
    
    
    --
    
    
    (100
    )
    
    (100
    )Net
    
    
    --
    
    
    34
    
    
    --
    
    
    34Total Unused
      Borrowing Capability
    
    $
    1,234
    
    $
    409
    
    $
    --
    
    $
    1,643








As of March 31,
2005, the Ohio Companies and Penn had the aggregate capability to issue
approximately $4.3 billion of additional FMB on the basis of property additions
and retired bonds under the terms of their respective mortgage indentures. The
issuance of FMB by OE and CEI are also subject to provisions of their 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
OE and CEI to incur additional secured debt not otherwise permitted by a
specified exception of up to $650 million and $565 million, respectively, as of
March 31, 2005. Under the provisions of its senior note indenture,
JCP&L may issue additional FMB only as collateral for senior notes. As of
March 31, 2005, JCP&L had the capability to issue $578 million of
additional senior notes upon the basis of FMB collateral. Based upon applicable
earnings coverage tests in their respective charters, OE, Penn, TE and JCP&L
could issue a total of $4.0 billion of preferred stock (assuming no additional
debt was issued) as of March 31, 2005. CEI, Met-Ed and Penelec have no
restrictions on the issuance of preferred stock.





As of March 31,
2005, approximately $1.0 billion remained under FirstEnergy's shelf registration
statement, filed with the SEC in 2003, to support future securities issues. The
shelf registration provides the flexibility to issue and sell various types of
securities, including common stock, debt securities, and share purchase
contracts and related share purchase units.





32




FirstEnergy’s
working capital and short-term borrowing needs are met principally with a
syndicated $1 billion three-year revolving credit facility maturing in June
2007. Combined with FirstEnergy’s syndicated $375 million three-year facility
maturing in October 2006, a $125 million three-year facility for OE maturing in
October 2006, and a syndicated $250 million two-year facility for OE maturing in
May 2005, primary syndicated credit facilities total $1.75 billion. These
revolving credit facilities, combined with an aggregate $550 million of accounts
receivable financing facilities for OE, CEI, TE, Met-Ed, Penelec and Penn, are
intended to provide liquidity to meet short-term working capital requirements
for FirstEnergy and its subsidiaries. Total unused borrowing capability under
existing facilities and accounts receivable financing facilities totaled $1.9
billion as of March 31, 2005.


Borrowings under
these facilities are conditioned on maintaining compliance with certain
financial covenants in the agreements. FirstEnergy and OE are each 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. As of
March 31, 2005, FirstEnergy’s and OE’s fixed charge coverage ratios, as
defined under the credit agreements, were 4.47 to 1 and 6.87 to 1, respectively.
FirstEnergy's and OE's debt to total capitalization ratios, as defined under the
credit agreements, were 0.55 to 1 and 0.40 to 1, respectively. The ability to
draw on each of these facilities is also conditioned upon FirstEnergy or OE
making certain representations and warranties to the lending banks prior to
drawing on their respective facilities, including a representation that there
has been no material adverse change in their business, condition (financial or
otherwise), results of operations, or prospects.





Neither
FirstEnergy's nor OE’s primary credit facilities contain any provisions that
either restrict their ability to borrow or accelerate repayment of outstanding
advances as a result of any change in their credit ratings. Each primary
facility does contain "pricing grids", whereby the cost of funds borrowed under
the facility is related to the credit ratings of the company borrowing the
funds.





FirstEnergy’s
regulated companies have the ability to borrow from each other and the holding
company to meet their short-term working capital requirements. A similar but
separate arrangement exists among FirstEnergy’s unregulated companies. FESC
administers these two money pools and tracks surplus funds of FirstEnergy and
the respective regulated and unregulated subsidiaries, as well as proceeds
available from bank borrowings. For the regulated companies, available bank
borrowings include $1.75 billion from FirstEnergy and OE’s revolving credit
facilities. For the unregulated companies, available bank borrowings include
only FirstEnergy’s $1.375 billion of 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
their respective pool and is based on the average cost of funds available
through the pool. The average interest rate for borrowings in the first quarter
of 2005 was 2.66% for the regulated companies’ money pool and 2.68% for the
unregulated companies' money pool.





On March 18,
2005, S&P stated that FirstEnergy’s Sammis NSR settlement was a very
favorable step for FirstEnergy, although it would not immediately affect
FirstEnergy’s ratings or outlook. S&P noted that it continues to monitor the
refueling outage at the Perry nuclear plant, which includes a detailed
inspection by the NRC, and that if FirstEnergy should exit the outage
without significant negative findings or delays the ratings outlook would be
revised to positive.





On March 14,
2005, CEI redeemed all 500,000 outstanding shares of its Serial Preferred Stock,
$7.40 Series A at a price of $101 per share plus accrued dividends to the date
of the redemption. Also on March 14, 2005, CEI redeemed all 474,000 outstanding
shares of its Serial Preferred Stock, Adjustable Rate Series L at a price of
$100 per share plus accrued dividends to the date of the
redemption.





On May 16,
2005, Penn intends to redeem all 127,500 outstanding shares of 7.625% preferred
stock at $102.29 per share and all 250,000 outstanding shares of 7.75% preferred
stock at $100 per share, both plus accrued dividends to the date of
redemption.





On June 1, 2005, CEI intends to redeem all of its 40,000 outstanding
shares of $7.35 Series C preferred stock at $101.00 per share, plus accrued
dividends to the date of redemption.





***Cash
Flows From Investing Activities***


Net cash flows used
in investing activities resulted principally from property additions. Regulated
services expenditures for property additions primarily include expenditures
supporting the distribution of electricity. Capital expenditures by the power
supply management services segment are principally generation-related. The
following table summarizes first quarter 2005 and 2004 investments by
FirstEnergy’s regulated services, power supply management services and other
segments:







33








**Summary
      of Cash Flows**
    
    **Property****Used
      for Investing Activities**
    
    **Additions**
    
    **Investments**
    
    **Other**
    
    **Total****2005
      First Quarter Sources (Uses)**
    
    ***(In
      millions)***Regulated
      services
    
    $
    (141
    )
    $
    23
    
    $
    3
    
    $
    (115
    )Power supply
      management services
    
    
    (81
    )
    
    (1
    )
    
    --
    
    
    (82
    )Other
    
    
    (3
    )
    
    16
    
    
    (13
    )
    
    --Reconciling
      items
    
    
    (4
    )
    
    20
    
    
    --
    
    
    16Total
    
    $
    (229
    )
    $
    58
    
    $
    (10
    )
    $
    (181
    )**2004
      First Quarter Sources (Uses)**Regulated
      services
    
    $
    (91
    )
    $
    (49
    )
    $
    (2
    )
    $
    (142
    )Power supply
      management services
    
    
    (44
    )
    
    (1
    )
    
    --
    
    
    (45
    )Other
    
    
    (1
    )
    
    (7
    )
    
    2
    
    
    (6
    )Reconciling
      items
    
    
    (2
    )
    
    (27
    )
    
    (20
    )
    
    (49
    )Total
    
    $
    (138
    )
    $
    (84
    )
    $
    (20
    )
    $
    (242
    )




Net cash used for
investing activities in the first quarter of 2005 was $61 million lower compared
with the same period of 2004. The decrease was primarily due to higher proceeds
of $42 million from assets sales (see Note 6 to the consolidated financial
statements), the absence of a $51 million NUG trust contribution in 2004 and
increased other investment earnings, partially offset by a $91 million increase
in property additions.




During the remaining
three quarters of 2005, capital requirements for property additions and capital
leases are expected to be approximately $825 million, including $20 million for
nuclear fuel. FirstEnergy has additional requirements of approximately $172
million to meet sinking fund requirements for preferred stock and maturing
long-term debt during the remainder of 2005. These cash requirements are
expected to be satisfied from internal cash and short-term credit
arrangements.





FirstEnergy’s
capital spending for the period 2005-2007 is expected to be about $3.3 billion
(excluding nuclear fuel), of which $998 million applies to 2005. Investments for
additional nuclear fuel during the 2005-2007 period are estimated to be
approximately $274 million, of which approximately $53 million applies to 2005.
During the same period, FirstEnergy’s nuclear fuel investments are expected to
be reduced by approximately $280 million and $86 million respectively, as the
nuclear fuel is consumed.





**GUARANTEES
AND OTHER ASSURANCES**





As part of normal
business activities, FirstEnergy enters into various agreements on behalf of its
subsidiaries to provide financial or performance assurances to third parties.
Such agreements include contract guarantees, surety bonds, and LOCs. Some of the
guaranteed contracts contain ratings contingent collateralization
provisions.





34





As of March 31,
2005, the maximum potential future payments under outstanding guarantees and
other assurances totaled $2.4 billion as summarized below:





**Maximum****Guarantees
      and Other Assurances**
    
    **Exposure*****(In
      millions)***FirstEnergy
      Guarantees of Subsidiaries:Energy and
      Energy-Related Contracts(1)
    
    $
    909Other(2)
    
    
    1491,058Surety
      Bonds
    
    
    267Letters of
      Credit(3)(4)
    
    
    1,059Total
      Guarantees and Other Assurances
    
    $
    2,384





(1)
    Issued for a
      one-year term, with a 10-day termination right by
    FirstEnergy.


(2)
    Issued for
      various terms.


(3)
    Includes $141
      million issued for various terms under LOC capacity available under
      FirstEnergy’srevolving
      credit agreement and $299 million outstanding in support
      of pollution
      control revenue bondsissued with
      various maturities.


(4)
    Includes
      approximately $194 million pledged in connection with the sale and
      leaseback of
      Beaver ValleyUnit 2 by CEI
      and TE, $291 million pledged in connection
      with the sale
      and leaseback of Beaver Valley Unit 2by OE and $134
      million pledged
      in connection
      with the sale and leaseback of Perry Unit 1 by
OE.





FirstEnergy
guarantees energy and energy-related payments of its subsidiaries involved in
energy marketing activities - principally to facilitate normal
physical transactions involving electricity, gas, emission allowances and coal.
FirstEnergy also provides guarantees to various providers of subsidiary
financing principally for the acquisition of property, plant and equipment.
These agreements legally obligate FirstEnergy and its subsidiaries to fulfill
the obligations of those subsidiaries directly involved in energy and
energy-related transactions or financings where the law might  otherwise limit the
counterparties’ claims. If demands of a counterparty were to exceed the ability
of a subsidiary to satisfy existing obligations, FirstEnergy’s guarantee enables
the counterparty’s legal claim to be satisfied by FirstEnergy’s other assets.
The likelihood that such parental guarantees will increase amounts otherwise
paid by FirstEnergy to meet its obligations incurred in connection with ongoing
energy-related contracts is remote.





While these types of
guarantees are normally parental commitments for the future payment of
subsidiary obligations, subsequent to the occurrence of a credit rating
downgrade or “material adverse event” the immediate posting of cash collateral or
provision of an LOC may be required of the subsidiary. The following table
summarizes collateral provisions in effect as of March 31,
2005:





**Total**
    
    **Collateral
      Paid**
    
    **Remaining****Collateral
      Provisions**
    
    **Exposure**
    
    **Cash**
    
    **LOC**
    
    **Exposure(1)*****(In
      millions)***Credit rating
      downgrade
    
    $
    364
    
    $
    153
    
    $
    18
    
    $
    193Adverse
      event
    
    
    42
    
    
    --
    
    
    8
    
    
    34Total
    
    $
    406
    
    $
    153
    
    $
    26
    
    $
    227





(1)
    As of May 2,
      2005, FirstEnergy’s total exposure decreased to $357 million and the
      remaining exposure decreased to
      $183 million -
      net of $148 million of cash collateral and $26 million of LOC collateral
      provided to counterparties.





Most of
FirstEnergy’s surety bonds are backed by various indemnities common within the
insurance industry. Surety bonds and related guarantees provide additional
assurance to outside parties that contractual and statutory obligations will be
met in a number of areas including construction contracts, environmental
commitments and various retail transactions.





FirstEnergy has
guaranteed the obligations of the operators of the TEBSA project up to a maximum
of $6 million (subject to escalation) under the project's operations and
maintenance agreement. In connection with the sale of TEBSA in January 2004, the
purchaser indemnified FirstEnergy against any loss under this guarantee.
FirstEnergy has provided an LOC (currently at $47 million), which is renewable
and declines yearly based upon the senior outstanding debt of
TEBSA.





35





**OFF-BALANCE
SHEET ARRANGEMENTS**





FirstEnergy has
obligations that are not included on its Consolidated Balance Sheet related to
the sale and leaseback arrangements involving Perry Unit 1, Beaver Valley Unit 2
and the Bruce Mansfield Plant, which are reflected as part of the operating
lease payments. The present value of these sale and leaseback operating lease
commitments, net of trust investments, total $1.4 billion as of March 31,
2005.





CEI and TE sell
substantially all of their retail customer receivables to CFC, a wholly owned
subsidiary of CEI. CFC subsequently transfers the receivables to a trust (a
"qualified special purpose entity" under SFAS 140) under an asset-backed
securitization agreement. This arrangement provided $142 million of off-balance
sheet financing as of March 31, 2005.





FirstEnergy has
equity ownership interests in certain various businesses that are accounted for
using the equity method. There are no undisclosed material contingencies related
to these investments. Certain guarantees that FirstEnergy does not expect to
have a material current or future effect on its financial condition, liquidity
or results of operations are disclosed under contractual obligations
above.





**MARKET RISK
INFORMATION**





FirstEnergy uses
various market risk sensitive instruments, including derivative contracts,
primarily to manage the risk of price and interest rate fluctuations.
FirstEnergy’s Risk Policy Committee, comprised of members of senior management,
provides general management oversight to risk management activities throughout
the Company.





***Commodity
Price Risk***





FirstEnergy is
exposed to market risk primarily due to fluctuating electricity, natural gas,
coal, nuclear fuel and emission allowance prices. To manage the volatility
relating to these exposures, it uses a variety of non-derivative and derivative
instruments, including forward contracts, options, futures contracts and swaps.
The derivatives are used principally for hedging purposes and, to a much lesser
extent, for trading purposes. All derivatives that
fall within the scope of SFAS 133 must be recorded at their fair market value
and be marked to market. The majority of FirstEnergy’s derivative hedging
contracts qualify for the normal purchases and normal sales SFAS 133 exemption
and are therefore excluded from the table below. Of those contracts not exempt
from such treatment, most are non-trading contracts that do not qualify for
hedge accounting treatment.Most of FirstEnergy’s non-hedge derivative
contracts represent non-trading positions that do not qualify for hedge
treatment under SFAS 133. The change in the fair value of commodity derivative
contracts related to energy production during the first quarter of 2005 is
summarized in the following table:





**Increase
      (Decrease) in the Fair Value of Commodity Derivative
      Contracts****Non-Hedge**
    
    **Hedge**
    
    **Total*****(In
      millions)*****Change
      in the Fair Value of Commodity Derivative
    Contracts:**Outstanding
      net asset as of January 1, 2005
    
    $
    62
    
    $
    2
    
    $
    64New contract
      value when entered
    
    
    --
    
    
    --
    
    
    --Additions/change
      in value of existing contracts
    
    
    (1
    )
    
    6
    
    
    5Change in
      techniques/assumptions
    
    
    --
    
    
    --
    
    
    --Settled
      contracts
    
    
    (7
    )
    
    1
    
    
    (6
    )Sale of retail
      natural gas contracts
    
    
    1
    
    
    (6
    )
    
    (5
    )Outstanding
      net asset as of March 31, 2005(1)
    
    $
    55
    
    $
    3
    
    $
    58**Non-commodity
      Net Assets as of March 31, 2005**:Interest Rate
      Swaps(2)
    
    
    --
    
    
    (27
    )
    
    (27
    )**Net
      Assets - Derivatives Contracts as of March 31,
    2005**
    
    $
    55
    
    $
    (24
    )
    $
    31**Impact
      of Changes in Commodity Derivative Contracts:****(3)**Income
      Statement Effects (Pre-Tax)
    
    $
    --
    
    $
    --
    
    $
    --Balance Sheet
      Effects:Other
      Comprehensive Income (Pre-Tax)
    
    $
    --
    
    $
    1
    
    $
    1Regulatory
      Liability
    
    $
    (7
    )
    $
    --
    
    $
    (7
    )





(1)  Includes $54 million
in non-hedge commodity derivative contracts which are offset by a regulatory
liability.


(2)  Interest rate swaps
are treated as fair value hedges. Changes in derivative values are offset by
changes in the hedged debts' premium or


discount (see Interest Rate Swap Agreements below).


(3)  Represents
the change in value of existing contracts, settled contracts and changes in
techniques/assumptions.








36





Derivatives are included on the Consolidated Balance Sheet as of March 31,
2005 as follows:








**Balance
      Sheet Classification**
    
    **Non-Hedge**
    
    **Hedge**
    
    **Total*****(In
      millions)*****Current-**Other
      assets
    
    $
    --
    
    $
    2
    
    $
    2Other
      liabilities
    
    
    (1
    )
    
    --
    
    
    (1
    )**Non-Current-**Other deferred
      charges
    
    
    56
    
    
    2
    
    
    58Other
      noncurrent liabilities
    
    
    --
    
    
    (28
    )
    
    (28
    )Net
      assets
    
    $
    55
    
    $
    (24
    )
    $
    31








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








**Source
      of Information****—Fair
      Value by Contract Year**
    
    **2005****(1)**
    
    **2006**
    
    **2007**
    
    **2008**
    
    **2009**
    
    **Thereafter**
    
    **Total*****(In
      millions)***Prices
      actively quoted(2)
    
    $
    5
    
    $
    2
    
    $
    1
    
    $
    --
    
    $
    --
    
    $
    --
    
    $
    8Sale of retail
      natural gas contracts(2)
    
    
    (4
    )
    
    (1
    )
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    (5
    )Other external
      sources(3)
    
    
    11
    
    
    10
    
    
    --
    
    
    --
    
    
    --
    
    
    --
    
    
    21Prices based
      on models
    
    
    --
    
    
    --
    
    
    10
    
    
    9
    
    
    7
    
    
    8
    
    
    34Total(4)
    
    $
    12
    
    $
    11
    
    $
    11
    
    $
    9
    
    $
    7
    
    $
    8
    
    $
    58





(1)  For the last three
quarters of 2005.


(2)  Exchange
traded.


(3)  Broker quote
sheets.


(4)  Includes $54 million
in non-hedge commodity derivative contracts which are offset by a regulatory
liability.





FirstEnergy performs
sensitivity analyses to estimate its exposure to the market risk of its
commodity positions. A hypothetical 10% adverse shift (an increase or decrease
depending on the derivative position) in quoted market prices in the near term
on both FirstEnergy's trading and nontrading derivative instruments would not
have had a material effect on its consolidated financial position (assets,
liabilities and equity) or cash flows as of March 31, 2005. Based on
derivative contracts held as of March 31, 2005, an adverse 10% change in
commodity prices would decrease net income by approximately $1 million for the
next twelve months.


***Interest
Rate Swap Agreements***





FirstEnergy utilizes
fixed-to-floating interest rate swap agreements, as part of its ongoing effort
to manage the interest rate risk of its debt portfolio. These derivatives are
treated as fair value hedges of fixed-rate, long-term debt issues - protecting against
the risk of changes in the fair value of fixed-rate debt instruments due to
lower interest rates. Swap maturities, call options, fixed interest rates and
interest payment dates match those of the underlying obligations. During the
first quarter of 2005, FirstEnergy executed two new interest rate swaps with a
notional amount of $50 million each ($100 million total notional amount) on
underlying EUOC and FirstEnergy senior notes with an average fixed rate of
6.51%. As of March 31, 2005, the debt underlying the $1.75 billion
outstanding notional amount of interest rate swaps had a weighted average fixed
interest rate of 5.59%, which the swaps have effectively converted to a current
weighted average variable interest rate of 4.32%.








37





***Interest
Rate Swaps***





**March
      31, 2005**
    
    **December
      31, 2004****Notional**
    
    **Maturity**
    
    **Fair**
    
    **Notional**
    
    **Maturity**
    
    **Fair****Denomination**
    
    **Amount**
    
    **Date**
    
    **Value**
    
    **Amount**
    
    **Date**
    
    **Value*****(Dollars
      in millions)***Fixed to
      Floating Rate(Fair value
      hedges)
    
    $
    200
    
    
    2006
    
    $
    (3
    )
    $
    200
    
    
    2006
    
    $
    (1
    )100
    
    
    2008
    
    
    (3
    )
    
    100
    
    
    2008
    
    
    (1
    )100
    
    
    2010
    
    
    (2
    )
    
    100
    
    
    2010
    
    
    1100
    
    
    2011
    
    
    --
    
    
    100
    
    
    2011
    
    
    2450
    
    
    2013
    
    
    (7
    )
    
    400
    
    
    2013
    
    
    4100
    
    
    2014
    
    
    --
    
    
    100
    
    
    2014
    
    
    2150
    
    
    2015
    
    
    (9
    )
    
    150
    
    
    2015
    
    
    (7
    )200
    
    
    2016
    
    
    (2
    )
    
    200
    
    
    2016
    
    
    1150
    
    
    2018
    
    
    3
    
    
    150
    
    
    2018
    
    
    550
    
    
    2019
    
    
    2
    
    
    50
    
    
    2019
    
    
    2150
    
    
    2031
    
    
    (6
    )
    
    100
    
    
    2031
    
    
    (4
    )$
    1,750
    
    
    
    
    $
    (27
    )
    $
    1,650
    
    
    
    
    $
    4





***Equity
Price Risk***





Included in nuclear
decommissioning trusts are marketable equity securities carried at their market
value of approximately $956 million and $951 million as of March 31, 2005
and December 31, 2004, respectively. A hypothetical 10% decrease in prices
quoted by stock exchanges would result in a $96 million reduction in fair value
as of March 31, 2005.





**CREDIT
RISK**


Credit risk is the
risk of an obligor’s failure to meet the terms of any investment contract, loan
agreement or otherwise perform as agreed. Credit risk arises from all activities
in which success depends on issuer, borrower or counterparty performance,
whether reflected on or off the balance sheet. FirstEnergy engages in
transactions for the purchase and sale of commodities including gas,
electricity, coal and emission allowances. These transactions are often with
major energy companies within the industry.


FirstEnergy
maintains credit policies with respect to its counterparties to manage overall
credit risk. This includes performing independent risk evaluations, actively
monitoring portfolio trends and using collateral and contract provisions to
mitigate exposure. As part of its credit program, FirstEnergy aggressively
manages the quality of its portfolio of energy contracts evidenced by a current
weighted average risk rating for energy contract counterparties of BBB
(S&P). As of March 31, 2005, the largest credit concentration was with
one party, currently rated investment grade, that represented 7%
of FirstEnergy's total credit risk. Within its unregulated energy
subsidiaries, 99% of credit exposures, net of collateral and reserve, were with
investment-grade counterparties as of March 31, 2005.





**Outlook**





***State
Regulatory Matters***





In Ohio, New Jersey and
Pennsylvania, laws applicable to electric industry restructuring contain similar
provisions that are reflected in the Companies' respective state regulatory
plans. These provisions include:





·
    restructuring
      the electric generation business and allowing the Companies' customers to
      select a competitive electric generation supplier other than the
      Companies;·
    establishing
      or defining the PLR obligations to customers in the Companies' service
      areas;·
    providing the
      Companies with the opportunity to recover potentially stranded investment
      (or transition costs) not otherwise recoverable in a competitive
      generation market;·
    itemizing
      (unbundling) the price of electricity into its component elements -
      including generation, transmission, distribution and stranded costs
      recovery charges;·
    continuing
      regulation of the Companies' transmission and distribution systems;
      and·
    requiring
      corporate separation of regulated and unregulated business
      activities.





38





The EUOC recognize,
as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU 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 regulatory 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.





**Regulatory
      Assets***
    
    **March
      31,**
    
    **December
      31,**
    
    **Increase****2005**
    
    **2004**
    
    **(Decrease)*****(In
      millions)***OE
    
    $
    1,022
    
    $
    1,116
    
    $
    (94
    )CEI
    
    
    925
    
    
    959
    
    
    (34
    )TE
    
    
    349
    
    
    375
    
    
    (26
    )JCP&L
    
    
    2,268
    
    
    2,176
    
    
    92Met-Ed
    
    
    750
    
    
    693
    
    
    57Penelec
    
    
    278
    
    
    200
    
    
    78ATSI
    
    
    14
    
    
    13
    
    
    1Total
    
    $
    5,606
    
    $
    5,532
    
    $
    74





*  Penn had net
regulatory liabilities of approximately $27 million and $18 million included in
Noncurrent


Liabilities on the Consolidated Balance Sheet as of March 31, 2005 and
December 31, 2004, respectively.








Regulatory assets by
source are as follows:








**Regulatory
      Assets By Source**
    
    **March
      31,**
    
    **December
      31,**
    
    **Increase****2005**
    
    **2004**
    
    **(Decrease)*****(In
      millions)***Regulatory
      transition costs
    
    $
    4,881
    
    $
    4,889
    
    $
    (8
    )Customer
      shopping incentives*
    
    
    668
    
    
    612
    
    
    56Customer
      receivables for future income taxes
    
    
    296
    
    
    246
    
    
    50Societal
      benefits charge
    
    
    40
    
    
    51
    
    
    (11
    )Loss on
      reacquired debt
    
    
    87
    
    
    89
    
    
    (2
    )Employee
      postretirement benefits costs
    
    
    62
    
    
    65
    
    
    (3
    )Nuclear
      decommissioning, decontaminationand spent fuel
      disposal costs
    
    
    (163
    )
    
    (169
    )
    
    6Asset removal
      costs
    
    
    (345
    )
    
    (340
    )
    
    (5
    )Property
      losses and unrecovered plant costs
    
    
    45
    
    
    50
    
    
    (5
    )Other
    
    
    35
    
    
    39
    
    
    (4
    )Total
    
    $
    5,606
    
    $
    5,532
    
    $
    74








*  The Ohio Companies
are deferring customer shopping incentives and interest costs as new regulatory
assets


in accordance with
the transition and rate stabilization plans. These regulatory assets, totaling
$668 million as


of March 31,
2005 (OE - $250 million, CEI - $320 million, TE - $98 million) 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.





***Reliability
Initiatives***




FirstEnergy is
proceeding with the implementation of the recommendations regarding enhancements
to regional reliability that were to be completed subsequent to 2004 and will
continue to periodically assess the FERC-ordered Reliability Study
recommendations for forecasted 2009 system conditions, recognizing revised load
forecasts and other changing system conditions which may impact the
recommendations. Thus far, implementation of the recommendations has not
required, nor is expected to require, substantial investment in new, or material
upgrades, to existing equipment. FirstEnergy notes, however, that FERC or other
applicable government agencies and reliability coordinators may take a different
view as to recommended enhancements or may recommend additional enhancements in
the future that could require additional, material expenditures. Finally, the
PUCO is continuing to review FirstEnergy's 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.





39




As a result of
outages experienced in JCP&L's service area in 2002 and 2003, the NJBPU had
implemented reviews into JCP&L's service reliability. On March 29,
2004, the NJBPU adopted a Memorandum of Understanding (MOU) that set out
specific tasks related to service reliability to be performed by JCP&L and a
timetable for completion and endorsed JCP&L's ongoing actions to implement
the MOU. On June 9, 2004, the NJBPU approved a Stipulation that
incorporates the final report of an SRM who made recommendations on appropriate
courses of action necessary to ensure system-wide reliability and the Executive
Summary and Recommendation portions of the final report of a focused audit of
JCP&L's Planning and Operations and Maintenance programs and practices
(Focused Audit). A Final Order in the Focused Audit docket was issued by the
NJBPU on July 23, 2004. On February 11, 2005, JCP&L met with the
Ratepayer Advocate to discuss reliability improvements. JCP&L continues to
file compliance reports reflecting activities associated with the MOU and
Stipulation.





See Note 13 to the
consolidated financial statements for a more detailed discussion of reliability
initiatives, including actions by the PPUC, that impact Met-Ed, Penelec and
Penn.





***Ohio***





The Ohio Companies'
revised Rate Stabilization Plan extends current generation prices through 2008,
ensuring adequate generation supply at stabilized prices, and continues the Ohio
Companies' 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 for OE from 2006 to as late as 2007; for CEI from 2008 to as late as
      mid-2009 and for TE from mid-2007 to as late as
  mid-2008;





·
    deferral of
      interest costs on the accumulated customer shopping incentives as new
      regulatory assets; and





·
    ability to
      request increases in generation charges during 2006 through 2008, under
      certain limited conditions, for increases in fuel costs and
      taxes.





On December 9,
2004, the PUCO rejected the auction price results from a required competitive
bid process and issued an entry stating that the pricing under the approved
revised Rate Stabilization Plan will take effect on January 1, 2006. The
PUCO may require the Ohio Companies to undertake, no more often than annually, a
similar competitive bid process to secure generation for the years 2007 and
2008. Any acceptance of future competitive bid results would terminate the Rate
Stabilization Plan pricing, but not the related approved accounting, and not
until twelve months after the PUCO authorizes such termination.





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





See Note 13 to the
consolidated financial statements for further details and a complete discussion
of regulatory matters in Ohio.





***New
Jersey***





The July 2003 NJBPU
decision on JCP&L's base electric rate proceeding ordered a Phase II
proceeding be conducted to review whether JCP&L is in compliance with
current service reliability and quality standards. The NJBPU also ordered that
any expenditures and projects undertaken by JCP&L to increase its system's
reliability be reviewed as part of the Phase II proceeding, to determine their
prudence and reasonableness for rate recovery. In that Phase II proceeding, the
NJBPU could increase JCP&L’s return on equity to 9.75% or decrease it to
9.25%, depending on its assessment of the reliability of JCP&L's service.
Any reduction would be retroactive to August 1, 2003. On July 16,
2004, JCP&L filed the Phase II petition and testimony with the NJBPU,
requesting an increase in base rates of $36 million for the recovery of system
reliability costs and a 9.75% return on equity. The filing also requests an
increase to the MTC deferred balance recovery of approximately $20 million
annually. The Ratepayer Advocate filed testimony on November 16, 2004, and
JCP&L submitted rebuttal testimony on January 4, 2005. The Ratepayer
Advocate surrebuttal testimony was submitted February 8, 2005. Discovery
and settlement conferences are ongoing.





40





In accordance with
an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7,
2004 supporting a continuation of the current level and duration of the funding
of TMI-2 decommissioning costs by New Jersey customers without a reduction,
termination or capping of the funding. On September 30, 2004, JCP&L
filed an updated TMI-2 decommissioning study. This study resulted in an updated
total decommissioning cost estimate of $729 million (in 2003 dollars) compared
to the estimated $528 million (in 2003 dollars) from the prior 1995
decommissioning study. The Ratepayer Advocate filed comments on
February 28, 2005. On March 18, 2005, JCP&L filed a response to
those comments. A schedule for further proceedings has not yet been
set.


See Note 13 to the
consolidated financial statements for further details and a complete discussion
of regulatory matters in New Jersey.





***Pennsylvania***





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





On January 12,
2005, Met-Ed and Penelec filed, before the PPUC, a request for deferral of
transmission-related costs beginning January 1, 2005, estimated to be
approximately $8 million per month.





See Note 13 to the
consolidated financial statements for further details and a complete discussion
of regulatory matters in Pennsylvania.





***Transmission***




On
September 16, 2004, the FERC issued an order that imposed additional
obligations on CEI under certain pre-Open Access transmission contracts among
CEI and the cities of Cleveland and Painesville, Ohio. Under the FERC's
decision, CEI may be responsible for a portion of new energy market charges
imposed by MISO when its energy markets begin in the spring of 2005. CEI filed
for rehearing of the order from the FERC on October 18, 2004. On
April 15, 2005, the FERC issued an order on rehearing that "carves out"
these contracts from the MISO Day 2 market. While the order on rehearing is
favorable to CEI, the impact of the FERC decision on CEI is dependent upon many
factors, including the arrangements made by the cities for transmission service
and MISO's ability to administer the contracts. Accordingly, the impact of this
decision cannot be determined at this time.





On November 1,
2004, ATSI requested authority from the FERC to defer approximately $54 million
of vegetation management costs ($14 million deferred as of March 31, 2005)
estimated to be incurred from 2004 through 2007. On March 4, 2005, the FERC
approved ATSI's request to defer those costs. ATSI expects to file an
application with FERC in the first quarter of 2006 for recovery of the deferred
costs.





ATSI and MISO filed
with the FERC on December 2, 2004, seeking approval for ATSI to have
transmission rates established based on a FERC-approved cost of service -
formula rate included in Attachment O under the MISO tariff. The ATSI Network
Service net revenue requirement increased under the formula rate to
approximately $159 million. On January 28, 2005, the FERC accepted for
filing the revised tariff sheets to become effective February 1, 2005,
subject to refund, and ordered a public hearing be held to address the
reasonableness of the proposal to eliminate the voltage-differentiated rate
design for the ATSI zone. On April 4, 2005, a settlement with all parties
to the proceeding was filed with the FERC that provides for recovery of the
full amount of the rate increase permitted under the formula.





***Environmental
Matters***


The Companies accrue
environmental liabilities only when they conclude that it is probable that they
have an obligation for such costs and can reasonably determine the amount of
such costs. Unasserted claims are reflected in the Companies’ determination of
environmental liabilities and are accrued in the period that they are both
probable and reasonably estimable.


41





*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 March 10, 2005, the EPA finalized the "Clean Air
Interstate Rule" covering a total of 28 states (including Michigan, New Jersey,
Ohio and Pennsylvania) and the District of Columbia based on proposed findings
that air emissions from 28 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. CAIR will require additional
reductions of NO x and SO 2 emissions in two
phases (Phase I in 2009 for NO x , 2010 for
SO 2 and Phase II in
2015 for both NOx and SO 2 ). The Companies’
Michigan, Ohio and Pennsylvania fossil-fired generation facilities will be
subject to the caps on SO 2 and NO x emissions, whereas
our New Jersey fossil-fired generation facilities will be subject to a cap on
NO x emissions only.
According to the EPA, SO 2 emissions will be
reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule,
with reductions reaching 73% (from 2003 levels) by 2015, capping SO 2 emissions in
affected states to just 2.5 million tons annually. NO x emissions will be
reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule,
with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional
NO x cap of 1.3 million
tons annually. The future cost of compliance with these regulations may be
substantial and will depend on 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 March 14, 2005, the EPA
finalized a cap-and-trade program to reduce mercury emissions in two phases from
coal-fired power plants. Initially, mercury emissions will decline by 2010 as a
"co-benefit" from implementation of SO 2 and NO x emission caps under
the EPA's CAIR program. Phase II of the mercury cap-and-trade program will cap
nationwide mercury emissions from coal-fired power plants at 15 tons per year by
2018. 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 (DOJ) 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. On March 18, 2005, OE and
Penn announced that they had reached a settlement with the EPA, the DOJ and
three states (Connecticut, New Jersey, and New York) that resolved all issues
related to the W. H. Sammis Plant New Source Review litigation. This settlement
agreement, which is in the form of a Consent Decree subject to a thirty-day
public comment period that ended on April 29, 2005 and final approval by the
District Court Judge, requires OE and Penn to reduce emissions from the W. H.
Sammis Plant and other plants through the installation of pollution control
devices requiring capital expenditures currently estimated to be $1.1 billion
(primarily in the 2008 to 2011 time period). The settlement agreement also
requires OE and Penn to spend up to $25 million towards environmentally
beneficial projects, which include wind energy purchase power agreements over a
20-year term. OE and Penn also agreed to pay a civil penalty of $8.5 million.
Results for the first quarter of 2005 include the penalties payable by OE and
Penn of $7.8 million and $0.7 million, respectively. OE and Penn also accrued
$9.2 million and $0.8 million, respectively, for cash contributions toward
environmentally beneficial projects during the first quarter of
2005.





*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 percent through
2012.


The Companies cannot
currently estimate the financial impact of climate change policies, although the
potential restrictions on CO 2 emissions could
require significant capital and other expenditures. However, the CO 2 emissions per
kilowatt-hour of electricity generated by the Companies is lower than many
regional competitors due to the Companies' diversified generation sources which
include low or non-CO 2 emitting gas-fired
and nuclear generators.





42




FirstEnergy plans to
issue a report that will disclose the Companies’ environmental activities,
including their plans to respond to environmental requirements. FirstEnergy
expects to complete the report by December 1, 2005 and will post the report on
its web site, www.firstenergycorp.com .





*Regulation of
Hazardous Waste*




The Companies have
been named as PRPs at waste disposal sites, which may require cleanup under the
Comprehensive Environmental Response, Compensation, and Liability Act of 1980.
Allegations of disposal of hazardous substances at historical sites and the
liability involved are often unsubstantiated and subject to dispute; however,
federal law provides that all PRPs for a particular site are liable on a joint
and several basis. Therefore, environmental liabilities that are considered
probable have been recognized on the Consolidated Balance Sheet as of
March 31, 2005, based on estimates of the total costs of cleanup, the
Companies' proportionate responsibility for such costs and the financial ability
of other nonaffiliated entities to pay. In addition, JCP&L has accrued
liabilities for environmental remediation of former manufactured gas plants in
New Jersey; those costs are being recovered by JCP&L through a
non-bypassable SBC. Included in Current Liabilities and Other Noncurrent
Liabilities are accrued liabilities aggregating approximately $65 million as of
March 31, 2005.





See Note 12(B) to
the consolidated financial statements for further details and a complete
discussion of environmental matters.





***Other
Legal Proceedings***




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




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. The U.S. - Canada Power System Outage Task Force’s
final report in April 2004 on the outages 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 contained 46
"recommendations to prevent or minimize the scope of future blackouts."
Forty-five of those recommendations related to broad industry or policy matters
while one, including subparts, related to activities the Task Force recommended
be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the
causes of the August 14, 2003 power outages. FirstEnergy implemented
several initiatives, both prior to and since the August 14, 2003 power
outages, which were independently verified by NERC as complete in 2004 and were
consistent with these and other recommendations and collectively enhance the
reliability of its electric system. 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 completed in 2004 had a material effect on its
continuing 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 March 31, 2005 for any expenditures in excess
of those actually incurred through that date.





One complaint was
filed on August 25, 2004 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.





43





FENOC received a
subpoena in late 2003 from a grand jury sitting in the United States District
Court for the Northern District of Ohio, Eastern Division requesting the
production of certain documents and records relating to the inspection and
maintenance of the reactor vessel head at the Davis-Besse Nuclear Power Station.
On December 10, 2004, FirstEnergy received a letter from the United States
Attorney's Office stating that FENOC is a target of the federal grand jury
investigation into alleged false statements made to the NRC in the Fall of 2001
in response to NRC Bulletin 2001-01. The letter also said that the designation
of FENOC as a target indicates that, in the view of the prosecutors assigned to
the matter, it is likely that federal charges will be returned against FENOC by
the grand jury. On February 10, 2005, FENOC received an additional subpoena
for documents related to root cause reports regarding reactor head degradation
and the assessment of reactor head management issues at
Davis-Besse.


On April 21,
2005, the NRC issued a NOV and proposed a $5.45 million civil penalty related to
the degradation of the Davis-Besse reactor vessel head described above. Under
the NRC’s letter, FENOC has ninety days to respond to this NOV. FirstEnergy has
accrued the remaining liability for the proposed fine of  $3.45
million during the first quarter of 2005.





If it were ultimately determined that FirstEnergy or its subsidiaries has legal
liability based on the Davis-Besse head degradation, it could have a material
adverse effect on FirstEnergy's or its subsidiaries' financial condition and
results of operations.





On August 12,
2004, the NRC notified FENOC that it would 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,
which is owned and/or leased by OE, CEI, TE and Penn. On April 4,
2005, the NRC held a public forum to discuss FENOC’s performance at the Perry
Nuclear Power Plant as identified in the NRC's annual assessment letter to
FENOC. Similar public meetings are held with all nuclear power plant licensees
following issuance by the NRC of their annual assessments. According to the NRC,
overall the Perry Plant operated "in a manner that preserved public health and
safety" and met all cornerstone objectives although it remained under the
heightened NRC oversight since August 2004. During the public forum and in the
annual assessment, the NRC indicated that additional inspections will continue
and that the plant must improve performance to be removed from the
Multiple/Repetitive Degraded Cornerstone Column of the Action Matrix. If
performance does not improve, the NRC has a range of options under the Reactor
Oversight Process from increased oversight to possible impact to the plant’s
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 Ohio Companies, and the Davis-Besse extended outage, have
become the subject of a formal order of investigation. The SEC's formal order of
investigation also encompasses issues raised during the SEC's examination of
FirstEnergy and the Companies under the PUHCA. Concurrent with this
notification, FirstEnergy received a subpoena asking for background documents
and documents related to the restatements and Davis-Besse issues. On
December 30, 2004, FirstEnergy received a second subpoena asking for
documents relating to issues raised during the SEC's PUHCA examination.
FirstEnergy has cooperated fully with the informal inquiry and will continue to
do so with the formal investigation.





If it were
ultimately determined that FirstEnergy or its subsidiaries have legal liability
or are otherwise made subject to liability based on the above matters, it could
have a material adverse effect on FirstEnergy's or its subsidiaries' financial
condition and results of operations.





See Note 12(C) to
the consolidated financial statements for further details and a complete
discussion of other legal proceedings.





**NEW
ACCOUNTING STANDARDS AND INTERPRETATIONS**





*FIN 47, “Accounting for Conditional Asset Retirement
Obligations - an interpretation of FASB Statement No. 143”*





On March 30,
2005, the FASB issued this interpretation to clarify the scope and timing of
liability recognition for conditional asset retirement obligations. Under this
interpretation, companies are required to recognize a liability for the fair
value of an asset retirement obligation that is conditional on a future event,
if the fair value of the liability can be reasonably estimated. In instances
where there is insufficient information to estimate the liability, the
obligation is to be recognized in the first period in which sufficient
information becomes available to estimate its fair value. If the fair value
cannot be reasonably estimated, that fact and the reasons why must be disclosed.
This interpretation is effective no later than the end of fiscal years ending
after December 15, 2005. FirstEnergy is currently evaluating the effect
this standard will have on the financial statements.





44


**


*SFAS 123 (revised 2004), “Share-Based
Payment”*





In December 2004,
the FASB issued this revision to SFAS 123, which requires expensing stock
options in the financial statements. Important to applying the new standard is
understanding how to (1) measure the fair value of stock-based compensation
awards and (2) recognize the related compensation cost for those awards. For an
award to qualify for equity classification, it must meet certain criteria in
SFAS 123(R). An award that does not meet those criteria will be classified as a
liability and remeasured each period. SFAS 123(R) retains SFAS 123's
requirements on accounting for income tax effects of stock-based compensation.
In April 2005, the SEC delayed the effective date of SFAS 123(R) to annual,
rather than interim, periods that begin after June 15, 2005. The SEC’s new
rule results in a six-month deferral for FirstEnergy and other companies with a
fiscal year beginning January 1. The Company will be applying modified
prospective application, without restatement of prior interim periods. Any
potential cumulative adjustments have not been determined. FirstEnergy uses the
Black-Scholes option-pricing model to value options and will continue to do so
upon adoption of SFAS 123(R).





*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, FirstEnergy will continue
to evaluate its investments as required by existing authoritative
guidance.
















45





**OHIO
      EDISON COMPANY****CONSOLIDATED
      STATEMENTS OF INCOME AND COMPREHENSIVE
      INCOME****(Unaudited)******
    
    **Three
      Months Ended****March
      31,****2005**
    
    **2004****STATEMENTS
      OF INCOME**
    
    
    
    ***(In
      thousands)*****OPERATING
      REVENUES**
    
    
    
    
    $
    726,358
    
    $
    743,295**OPERATING
      EXPENSES AND TAXES:**Fuel
    
    
    
    
    
    11,916
    
    
    15,070Purchased
      power
    
    
    
    
    
    246,590
    
    
    249,881Nuclear
      operating costs
    
    
    
    
    
    95,653
    
    
    79,641Other
      operating costs
    
    
    
    
    
    83,179
    
    
    85,360Provision for
      depreciation
    
    
    
    
    
    26,052
    
    
    29,929Amortization
      of regulatory assets
    
    
    
    
    
    111,771
    
    
    113,695Deferral of
      new regulatory assets
    
    
    
    
    
    (24,795
    )
    
    (18,895
    )General
      taxes
    
    
    
    
    
    48,078
    
    
    48,566Income
      taxes
    
    
    
    
    
    54,972
    
    
    61,574Total
      operating expenses and taxes
    
    
    
    
    
    653,416
    
    
    664,821**OPERATING
      INCOME**
    
    
    
    
    
    72,942
    
    
    78,474**OTHER
      INCOME (net of income taxes)**
    
    
    
    
    
    423
    
    
    16,357**NET
      INTEREST CHARGES:**Interest on
      long-term debt
    
    
    
    
    
    15,609
    
    
    16,589Allowance for
      borrowed funds used during construction and capitalized
      interest
    
    
    
    
    
    (2,235
    )
    
    (1,381
    )Other interest
      expense
    
    
    
    
    
    2,594
    
    
    2,890Subsidiary's
      preferred stock dividend requirements
    
    
    
    
    
    640
    
    
    640Net interest
      charges
    
    
    
    
    
    16,608
    
    
    18,738**NET
      INCOME**
    
    
    
    
    
    56,757
    
    
    76,093**PREFERRED
      STOCK DIVIDEND REQUIREMENTS**
    
    
    
    
    
    659
    
    
    561**EARNINGS
      ON COMMON STOCK**
    
    
    
    
    $
    56,098
    
    $
    75,532**STATEMENTS
      OF COMPREHENSIVE INCOME****NET
      INCOME**
    
    
    
    
    $
    56,757
    
    $
    76,093**OTHER
      COMPREHENSIVE INCOME (LOSS):**Unrealized
      gain (loss) on available for sale securities
    
    
    
    
    
    (2,717
    )
    
    5,167Income tax
      related to other comprehensive income
    
    
    
    
    
    1,124
    
    
    (2,131
    )Other
      comprehensive income (loss), net of tax
    
    
    
    
    
    (1,593
    )
    
    3,036**TOTAL
      COMPREHENSIVE INCOME**
    
    
    
    
    $
    55,164
    
    $
    79,129The preceding
      Notes to Consolidated Financial Statements as they relate to Ohio Edison
      Company are an integral part of these
      statements.
   46
  **OHIO
      EDISON COMPANY****CONSOLIDATED
      BALANCE SHEETS****(Unaudited)****March
      31,**
    ****
    **December
      31,**
    ********
    ****
    ****
    ****
    **2005**
    ****
    **2004**
    ********
    ****
    ****
    ****
    ***(In
      thousands)*****ASSETS**UTILITY
      PLANT:In
      service
    
    
    
    
    $
    5,470,159
    
    $
    5,440,374Less -
      Accumulated provision for depreciation
    
    
    
    
    
    2,747,377
    
    
    2,716,8512,722,782
    
    
    2,723,523Construction
      work in progress-Electric
      plant
    
    
    
    
    
    233,967
    
    
    203,167Nuclear
      fuel
    
    
    
    
    
    39,468
    
    
    21,694273,435
    
    
    224,8612,996,217
    
    
    2,948,384OTHER
      PROPERTY AND INVESTMENTS:Investment in
      lease obligation bonds
    
    
    
    
    
    354,457
    
    
    354,707Nuclear plant
      decommissioning trusts
    
    
    
    
    
    445,704
    
    
    436,134Long-term
      notes receivable from associated companies
    
    
    
    
    
    208,364
    
    
    208,170Other
    
    
    
    
    
    42,720
    
    
    48,5791,051,245
    
    
    1,047,590CURRENT
      ASSETS:Cash and cash
      equivalents
    
    
    
    
    
    1,204
    
    
    1,230Receivables-Customers
      (less accumulated provisions of $6,179,000 and $6,302,000,
      respectively,for
      uncollectible accounts)
    
    
    
    
    
    267,911
    
    
    274,304Associated
      companies
    
    
    
    
    
    163,201
    
    
    245,148Other (less
      accumulated provisions of $82,000 and $64,000,
    respectively,for
      uncollectible accounts)
    
    
    
    
    
    20,602
    
    
    18,385Notes
      receivable from associated companies
    
    
    
    
    
    692,715
    
    
    538,871Materials and
      supplies, at average cost
    
    
    
    
    
    105,906
    
    
    90,072Prepayments
      and other
    
    
    
    
    
    25,981
    
    
    13,1041,277,520
    
    
    1,181,114DEFERRED
      CHARGES:Regulatory
      assets
    
    
    
    
    
    1,022,241
    
    
    1,115,627Property
      taxes
    
    
    
    
    
    61,419
    
    
    61,419Unamortized
      sale and leaseback costs
    
    
    
    
    
    58,896
    
    
    60,242Other
    
    
    
    
    
    71,327
    
    
    68,2751,213,883
    
    
    1,305,563$
    6,538,865
    
    $
    6,482,651CAPITALIZATION
      AND LIABILITIESCAPITALIZATION: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
    
    
    
    
    
    (48,711
    )
    
    (47,118
    )Retained
      earnings
    
    
    
    
    
    451,296
    
    
    442,198Total common
      stockholder's equity
    
    
    
    
    
    2,501,314
    
    
    2,493,809Preferred
      stock
    
    
    
    
    
    60,965
    
    
    60,965Preferred
      stock of consolidated subsidiary
    
    
    
    
    
    39,105
    
    
    39,105Long-term debt
      and other long-term obligations
    
    
    
    
    
    1,098,801
    
    
    1,114,9143,700,185
    
    
    3,708,793CURRENT
      LIABILITIES:Currently
      payable long-term debt
    
    
    
    
    
    397,256
    
    
    398,263Short-term
      borrowings-Associated
      companies
    
    
    
    
    
    75,969
    
    
    11,852Other
    
    
    
    
    
    134,072
    
    
    167,007Accounts
      payable-Associated
      companies
    
    
    
    
    
    151,151
    
    
    187,921Other
    
    
    
    
    
    7,498
    
    
    10,582Accrued
      taxes
    
    
    
    
    
    197,848
    
    
    153,400Other
    
    
    
    
    
    126,265
    
    
    74,6631,090,059
    
    
    1,003,688NONCURRENT
      LIABILITIES:Accumulated
      deferred income taxes
    
    
    
    
    
    726,080
    
    
    766,276Accumulated
      deferred investment tax credits
    
    
    
    
    
    59,135
    
    
    62,471Asset
      retirement obligation
    
    
    
    
    
    344,715
    
    
    339,134Retirement
      benefits
    
    
    
    
    
    309,915
    
    
    307,880Other
    
    
    
    
    
    308,776
    
    
    294,4091,748,621
    
    
    1,770,170COMMITMENTS
      AND CONTINGENCIES (Note 12)$
    6,538,865
    
    $
    6,482,651The preceding
      Notes to Consolidated Financial Statements as they relate to Ohio Edison
      Company are an integral part of these balance sheets.
 47
   **OHIO
      EDISON COMPANY****CONSOLIDATED
      STATEMENTS OF CASH FLOWS****(Unaudited)****Three
      Months Ended****March
      31,****2005**
    
    **2004*****(In
      thousands)*****CASH
      FLOWS FROM OPERATING ACTIVITIES:**Net
      income
    
    
    
    
    $
    56,757
    
    $
    76,093Adjustments to
      reconcile net income to net cash from operating
activities-Provision for
      depreciation
    
    
    
    
    
    26,052
    
    
    29,929Amortization
      of regulatory assets
    
    
    
    
    
    111,771
    
    
    113,695Deferral of
      new regulatory assets
    
    
    
    
    
    (24,795
    )
    
    (18,895
    )Nuclear fuel
      and lease amortization
    
    
    
    
    
    9,170
    
    
    11,261Amortization
      of lease costs
    
    
    
    
    
    33,030
    
    
    33,030Deferred
      income taxes and investment tax credits, net
    
    
    
    
    
    (24,627
    )
    
    (30,045
    )Accrued
      retirement benefit obligations
    
    
    
    
    
    2,034
    
    
    11,123Accrued
      compensation, net
    
    
    
    
    
    (4,007
    )
    
    4,522Decrease
      (Increase) in operating assets:Receivables
    
    
    
    
    
    86,123
    
    
    (51,935
    )Materials and
      supplies
    
    
    
    
    
    (15,834
    )
    
    (2,762
    )Prepayments
      and other current assets
    
    
    
    
    
    (12,877
    )
    
    (11,829
    )Increase
      (Decrease) in operating liabilities:Accounts
      payable
    
    
    
    
    
    (39,854
    )
    
    240,979Accrued
      taxes
    
    
    
    
    
    44,448
    
    
    (311,577
    )Accrued
      interest
    
    
    
    
    
    6,993
    
    
    5,443Other
    
    
    
    
    
    11,714
    
    
    5,991Net cash
      provided from operating activities
    
    
    
    
    
    266,098
    
    
    105,023**CASH
      FLOWS FROM FINANCING ACTIVITIES:**New
      Financing-Long-term
      debt
    
    
    
    
    
    --
    
    
    30,000Short-term
      borrowings, net
    
    
    
    
    
    31,182
    
    
    16,341Redemptions
      and Repayments-Long-term
      debt
    
    
    
    
    
    (15,787
    )
    
    (97,001
    )Dividend
      Payments-Common
      stock
    
    
    
    
    
    (47,000
    )
    
    (54,000
    )Preferred
      stock
    
    
    
    
    
    (659
    )
    
    (561
    )Net cash used
      for financing activities
    
    
    
    
    
    (32,264
    )
    
    (105,221
    )**CASH
      FLOWS FROM INVESTING ACTIVITIES:**Property
      additions
    
    
    
    
    
    (79,783
    )
    
    (37,661
    )Contributions
      to nuclear decommissioning trusts
    
    
    
    
    
    (7,885
    )
    
    (7,885
    )Loan
      repayments from (loans to) associated companies, net
    
    
    
    
    
    (154,038
    )
    
    48,912Other
    
    
    
    
    
    7,846
    
    
    (3,728
    )Net cash used
      for investing activities
    
    
    
    
    
    (233,860
    )
    
    (362
    )Net decrease
      in cash and cash equivalents
    
    
    
    
    
    (26
    )
    
    (560
    )Cash and cash
      equivalents at beginning of period
    
    
    
    
    
    1,230
    
    
    1,883Cash and cash
      equivalents at end of period
    
    
    
    
    $
    1,204
    
    $
    1,323The preceding
      Notes to Consolidated Financial Statements as they relate to Ohio Edison
      Company are an integral part of these
      statements.







48





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





























To the Stockholders
and Board of


Directors of Ohio
Edison Company:





We have reviewed the
accompanying consolidated balance sheet of Ohio Edison Company and its
subsidiaries as of March 31, 2005, and the related consolidated statements
of income, comprehensive income and cash flows for each of the three-month
periods ended March 31, 2005 and 2004. These interim financial statements
are the responsibility of the Company’s management.





We conducted our
review in accordance with the standards of the Public Company Accounting
Oversight Board (United States). A review of interim financial information
consists principally of applying analytical procedures and making inquiries of
persons responsible for financial and accounting matters. It is substantially
less in scope than an audit conducted in accordance with the standards of the
Public Company Accounting Oversight Board, the objective of which is the
expression of an opinion regarding the financial statements taken as a whole.
Accordingly, we do not express such an opinion.





Based on our review,
we are not aware of any material modifications that should be made to the
accompanying consolidated interim financial statements for them to be in
conformity with accounting principles generally accepted in the United States of
America.





We previously
audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheet as of
December 31, 2004, and the related consolidated statements of income,
capitalization, common stockholder’s equity, preferred stock, cash flows and
taxes for the year then ended, management’s assessment of the effectiveness of
the Company’s internal control over financial reporting as of December 31,
2004 and the effectiveness of the Company’s internal control over financial
reporting as of December 31, 2004; and in our report (which contained
references to the Company’s change in its method of accounting for asset
retirement obligations as of January 1, 2003 as discussed in Note 2(G) to
those consolidated financial statements and the Company’s change in its method
of accounting for the consolidation of variable interest entities as of
December 31, 2003 as discussed in Note 7 to those consolidated financial
statements) dated March 7, 2005, we expressed unqualified opinions thereon.
The consolidated financial statements and management’s assessment of the
effectiveness of internal control over financial reporting referred to above are
not presented herein. In our opinion, the information set forth in the
accompanying consolidated balance sheet information as of December 31,
2004, is fairly stated in all material respects in relation to the consolidated
balance sheet from which it has been derived.














PricewaterhouseCoopers
LLP


Cleveland,
Ohio


May 3,
2005





49





**OHIO EDISON
COMPANY**





**MANAGEMENT’S
DISCUSSION AND ANALYSIS OF**


**RESULTS OF
OPERATIONS AND FINANCIAL CONDITION**








OE is a wholly owned
electric utility subsidiary of FirstEnergy. OE and its wholly owned subsidiary,
Penn, conduct business in portions of Ohio and Pennsylvania, providing regulated
electric distribution services. The OE Companies also provide generation
services to those customers electing to retain the OE Companies as their power
supplier. The OE Companies provide power directly to wholesale customers under
previously negotiated contracts, as well as to some alternative energy suppliers
under OE’s transition plan. The OE Companies have unbundled the price of
electricity into its component elements - including generation, transmission,
distribution and transition charges. Power supply requirements of the OE
Companies are provided by FES -- an affiliated company.





**Results
of Operations**




Earnings on common
stock in the first quarter of 2005 decreased to $56 million from $76 million in
the first quarter of 2004. The earnings decrease in 2005 primarily resulted from
reduced operating revenues and other income and increased nuclear operating
costs, which were partially offset by decreased depreciation, changes in
amortization and deferrals of regulatory assets, lower fuel and purchased power
costs, and reduced financing costs.





Operating revenues
decreased by $17 million or 2.3% in the first quarter of 2005 compared with the
same period in 2004. Lower revenues primarily resulted from a $24 million
wholesale sales decrease partially offset by increases in retail generation and
distribution revenues of $6 million and $2 million, respectively.





Lower wholesale
revenues reflected decreased sales to FES of $28 million (20.3% KWH decrease)
due to reduced nuclear generation available for sale. The decreased FES sales
were partially offset by increased sales of $4 million to non-affiliated
customers (primarily MSG sales). Under its Ohio transition plan, OE is required
to provide the attractively-priced MSG to non-affiliated alternative suppliers
(see Outlook - Regulatory Matters).





Increased retail
generation revenues resulted from increased sales to industrial and commercial
customers of $5 million and $3 million, respectively, partially offset by a $2
million residential sales decrease. The increase in industrial and commercial
revenues reflected the effect of higher generation KWH sales (industrial - 4.1%
and commercial - 3.9%) and higher composite unit prices. The industrial KWH
growth was moderated by increased customer shopping. Generation services
provided to industrial customers by alternative suppliers as a percent of total
industrial sales delivered in OE’s service area increased by 2.1 percentage
points, which partially offset the effect of a 7.2% increase in industrial
sector deliveries. Reduced residential revenues were principally due to a 2.8%
KWH sales decrease reflecting increased residential customer shopping (1.7
percentage point increase). Commercial customer shopping remained relatively
unchanged.





Revenues from
distribution throughput increased $2 million in the first quarter of 2005
compared with the same period in 2004. Distribution deliveries to commercial and
industrial customers increased by $2 million and $1 million, respectively, in
2005 compared to 2004, reflecting increased KWH deliveries partially offset by
lower composite unit prices. The increased sales to the commercial and
industrial sectors resulted, in part, from an improving economy in OE's service
area. Distribution deliveries to residential customers decreased
slightly.





Under the Ohio
transition plan, OE provides incentives to customers to encourage switching to
alternative energy providers. OE’s revenues were reduced by $2 million from
additional credits in the first quarter of 2005 compared to the same period in
2004. These revenue reductions are deferred for future recovery under OE’s
transition plan and do not affect current period earnings. (See Regulatory
Matters below.)





50





Changes in electric
generation sales and distribution deliveries in the first quarter of 2005 from
the same quarter of 2004 are summarized in the following table:





**Changes
      in KWH Sales****Increase
      (Decrease)**Electric
      Generation:Retail
    
    
    1.3
    %Wholesale
    
    
    (17.4
    )%Total Electric
      Generation Sales
    
    
    (7.6
    )%Distribution
      Deliveries:Residential
    
    
    (0.7
    )%Commercial
    
    
    3.6
    %Industrial
    
    
    7.2
    %Total
      Distribution Deliveries
    
    
    3.1
    %





*Operating
Expenses and Taxes*





Total operating
expenses and taxes decreased by $11 million in the first quarter of 2005 from
the first quarter of 2004. The following table presents changes from the prior
year by expense category.








**Operating
      Expenses and Taxes - Changes****Increase
      (Decrease)**
    
    ***(In
      millions)***Fuel
      costs
    
    $
    (3
    )Purchased
      power costs
    
    
    (3
    )Nuclear
      operating costs
    
    
    16Other
      operating costs
    
    
    (2
    )Provision for
      depreciation
    
    
    (4
    )Amortization
      of regulatory assets
    
    
    (2
    )Deferral of
      new regulatory assets
    
    
    (6
    )General
      taxes
    
    
    --Income
      taxes
    
    
    (7
    )**Net
      decrease in operating expenses and taxes**
    
    $
    (11
    )








Lower fuel costs in
the first quarter of 2005, compared with the same quarter of 2004, resulted from
decreased nuclear generation - down 20.3%. Decreased purchased power costs
reflected lower KWH purchased partially offset by higher unit costs. Higher
nuclear operating costs were primarily due to the Perry nuclear plant scheduled
refueling outage (including an unplanned extension) in the first quarter of 2005
and the absence of nuclear refueling outages in the same period last year. The
decrease in other operating costs was primarily due to reduced labor costs and
lower employee benefit expenses.





The decrease in
depreciation in the first quarter of 2005 compared with the same quarter of 2004
was attributable to revised estimated service life assumptions for fossil
generating plants. Lower amortization of regulatory assets was due to decreased
amortization of Ohio transition regulatory assets, effective April 1, 2004.
The higher deferrals of new regulatory assets primarily resulted from higher
shopping incentive deferrals ($2 million) and deferred interest on shopping
incentives ($3 million).





*Other
Income*





Other income
decreased $16 million in the first quarter of 2005 compared with the same
quarter of 2004, primarily due to the accruals of an $8.5 million civil penalty
payable to the Department of Justice and $10 million for environmental projects
in connection with the Sammis Plant settlement (see Outlook - Environmental
Matters).





*Net Interest
Charges*





Net interest charges
continued to trend lower, decreasing by $2 million in the first quarter of 2005
compared with the same quarter of 2004, reflecting redemptions of $15 million of
outstanding debt during the first quarter of 2005.








51





**Capital
Resources and Liquidity**





OE’s cash
requirements in 2005 for operating expenses, construction expenditures,
scheduled debt maturities and preferred stock redemptions are expected to be met
without increasing OE’s net debt and preferred stock outstanding. Available
borrowing capacity under credit facilities will be used to manage working
capital requirements. Thereafter, OE expects to use a combination of cash from
operations and funds from the capital markets.





*Changes in Cash
Position*





OE's cash and cash
equivalents were approximately $1 million as of March 31, 2005 and
December 31, 2004.





*Cash Flows From
Operating Activities*





Cash provided from
operating activities during the first quarter of 2005 and 2004 period were as
follows:





**Operating
      Cash Flows**
    
    **2005**
    
    **2004*****(In
      millions)***Cash earnings
      (1)
    
    $
    185
    
    $
    231Working
      capital and other
    
    
    81
    
    
    (126
    )Total Cash
      Flows from Operating Actitivities
    
    $
    266
    
    $
    105





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




Cash earnings (in
the table above) are not a measure of performance calculated in accordance with
GAAP. FirstEnergy believes that cash earnings is a useful financial measure
because it provides investors and management with an additional means of
evaluating its cash-based operating performance. The following table reconciles
cash earnings with net income.





**Reconciliation
      of Cash Earnings**
    
    **2005**
    
    **2004*****(In
      millions)***Net Income
      (GAAP)
    
    $
    57
    
    $
    76Non-Cash
      Charges (Credits):Provision for
      depreciation
    
    
    26
    
    
    30Amortization
      of regulatory assets
    
    
    112
    
    
    114Nuclear fuel
      and capital lease amortization
    
    
    9
    
    
    11Deferral of
      new regulatory assets
    
    
    (25
    )
    
    (19
    )Deferred
      income taxes and investment tax credits, net
    
    
    (25
    )
    
    (30
    )Other non-cash
      charges
    
    
    31
    
    
    49Cash earnings
      (Non-GAAP)
    
    $
    185
    
    $
    231








Net cash from
operating activities increased $161 million in the first quarter of 2005,
compared with the first quarter of 2004, due to a $207 million increase from
changes in working capital partially offset by a $46 million decrease in cash
earnings as described above and under "Results from Operations". The increase in
working capital primarily reflects changes in receivables from associated
companies of $146 million and accounts payable to associated companies of $278
million, partially offset by changes in accrued taxes of $356 million. The
changes for accounts payable and accrued taxes primarily reflect a $249 million
reallocation of tax liabilities between associated companies under the tax
sharing agreement in 2004.





*Cash Flows From
Financing Activities*




Net cash used for
financing activities decreased to $32 million in the first quarter of 2005 from
$105 million in the first quarter of 2004. The decrease primarily reflected
lower debt redemptions and common stock dividend payments to FirstEnergy.





52




OE had approximately
$694 million of cash and temporary cash investments (which include short-term
notes receivable from associated companies) and $210 million of short-term
indebtedness as of March 31, 2005. OE has 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 authorization from the SEC to
incur short-term debt up to its charter limit of $49 million (including the
utility money pool). In addition, Penn has a $25 million receivables financing
facility. As of March 31, 2005, the facility was undrawn; it expires
June 30, 2005 and is expected to be renewed.





OE and Penn had the
aggregate capability to issue approximately $1.9 billion of additional FMB on
the basis of property additions and retired bonds under the terms of their
respective mortgage indentures. The issuance of FMB by OE is also subject to
provisions of its 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 OE to incur additional secured debt not otherwise
permitted by a specified exception of up to $650 million as of March 31,
2005. Based upon applicable earnings coverage tests in their respective
charters, OE and Penn could issue a total of $2.9 billion of preferred stock
(assuming no additional debt was issued) as of March 31, 2005.





OE has $409 million
of credit facilities, which were unused as of March 31, 2005, consisting of
a $125 million three-year facility maturing in October 2006, a syndicated $250
million two-year facility maturing in May 2005 and bank facilities of $34
million. These facilities are intended to provide liquidity to meet OE’s
short-term working capital requirements and would be available for investment in
the money pool with its regulated affiliates.





Borrowings under
these facilities are conditioned on maintaining compliance with certain
financial covenants in the agreements. OE is 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. As of March 31, 2005,
OE’s fixed charge coverage ratio, as defined under the credit agreements, was
6.87 to 1. OE's debt to total capitalization ratio, as defined under the credit
agreements, was 0.40 to 1. The ability to draw on each of its facilities is also
conditioned upon OE making certain representations and warranties to the lending
banks prior to drawing under the facilities, including a representation that
there has been no material adverse change in its business, condition (financial
or otherwise), results of operations, or prospects.





None of OE’s primary
credit facilities contain any provisions that either restrict its ability to
borrow or accelerate repayment of outstanding advances as a result of any change
in its credit ratings. Each primary facility does contain "pricing grids",
whereby the cost of funds borrowed under the facility is related to OE’s credit
ratings.





OE has the ability
to borrow from its regulated affiliates and FirstEnergy to meet its short-term
working capital requirements. FESC administers this money pool and tracks
surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving
a loan under the money pool agreements must repay the principal amount, together
with accrued interest, within 364 days of borrowing the funds. The rate of
interest is the same for each company receiving a loan from the pool and is
based on the average cost of funds available through the pool. The average
interest rate for borrowings in the first quarter of 2005 was
2.66%.





On April 6,
2004, Ohio Air Quality Development Authority pollution control bonds aggregating
$100 million and Ohio Water Development Authority pollution control bonds
aggregating $6.45 million, respectively, were refunded. The new bonds were
issued in a Dutch Auction interest rate mode, insured with municipal bond
insurance and secured by FMB.





On May 16,
2005, Penn intends to redeem all 127,500 outstanding shares of 7.625% preferred
stock at $102.29 per share and all 250,000 outstanding shares of 7.75% preferred
stock at $100 per share, both plus accrued dividends to the date of
redemption.





OE’s access to
capital markets and costs of financing are dependent on the ratings of its
securities and the securities of FirstEnergy. The ratings outlook from the
rating agencies on all such securities is stable.





On March 18,
2005, S&P stated that FirstEnergy’s Sammis NSR settlement was a very
favorable step for FirstEnergy, although it would not immediately affect
FirstEnergy’s ratings or outlook. S&P noted that it continues to monitor the
refueling outage at the Perry nuclear plant, which includes a detailed
inspection by the NRC, and that if FirstEnergy should exit the outage
without significant negative findings or delays the ratings outlook would be
revised to positive.





53





*Cash Flows From
Investing Activities*




Net cash used for
investing activities increased to $234 million in the first quarter of 2005 from
$0.4 million in the first quarter of 2004. The increase resulted primarily from
a $203 million increase of loans to associated companies and a $42 million
increase in property additions.





During the remaining
three quarters of 2005, capital requirements for property additions and capital
leases are expected to be approximately $175 million, including $19 million for
nuclear fuel. OE has additional requirements of approximately $120 million to
meet sinking fund requirements for preferred stock and maturing long-term debt
(excluding Penn's optional redemptions disclosed above) during the
remainder of 2005. These cash requirements are expected to be satisfied from
internal cash and short-term credit arrangements.





OE’s capital
spending for the period 2005-2007 is expected to be about $667 million
(excluding nuclear fuel), of which approximately $216 million applies to 2005.
Investments for additional nuclear fuel during the 2005-2007 period are
estimated to be approximately $145 million, of which about $36 million applies
to 2005. During the same period, its nuclear fuel investments are expected to be
reduced by approximately $126 million and $40 million, respectively, as the
nuclear fuel is consumed.





**Off-Balance
Sheet Arrangements**





Obligations not
included on OE’s Consolidated Balance Sheets primarily consist of sale and
leaseback arrangements involving Perry Unit 1 and Beaver Valley Unit 2. The
present value of these operating lease commitments, net of trust investments,
was $688 million as of March 31, 2005.





**Equity
Price Risk**


Included in OE’s
nuclear decommissioning trust investments are marketable equity securities
carried at their market value of approximately $244 million and $248 million as
of March 31, 2005 and December 31, 2004, respectively. A hypothetical
10% decrease in prices quoted by stock exchanges would result in a $24 million
reduction in fair value as of March 31, 2005. Changes in the fair value of
these investments are recorded in OCI unless recognized as a result of a sale or
recognized as regulatory assets or liabilities.


**Outlook**




The electric
industry continues to transition to a more competitive environment and all of
the OE Companies’ customers can select alternative energy suppliers. The OE
Companies continue to deliver power to residential homes and businesses through
their existing distribution system, which remains regulated. Customer rates have
been restructured into separate components to support customer choice. In Ohio
and Pennsylvania, the OE Companies 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 OE's customers elects to obtain power from an alternative supplier, OE
reduces the customer's bill with a "generation shopping credit," based on the
generation component (plus an incentive), and the customer receives a generation
charge from the alternative supplier. OE has continuing PLR responsibility to
its franchise customers through December 31, 2005. As part of OE's
transition plan, it is obligated to supply electricity to customers who do not
choose an alternative supplier. OE is also required to provide 560 MW of low
cost supply to unaffiliated alternative suppliers who serve customers within its
service area. FES acts as an alternate supplier for a portion of the load in
OE's franchise area.





OE's 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 for OE from 2006 to as late as 2007;
 
 ·
    deferral of
      interest costs on the accumulated customer shopping incentives as new
      regulatory assets; and
  54






·
    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 require 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, and not
until twelve months after the PUCO authorizes such termination.





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.





OE and Penn record
as regulatory assets costs which have been authorized by the PUCO, the PPUC and
the FERC for recovery from customers in future periods and, without such
authorization, would have been charged to income when incurred. OE’s regulatory
assets as of March 31, 2005 and December 31, 2004, were $1.0 billion
and $1.1 billion, respectively. OE is deferring customer shopping incentives and
interest costs as new regulatory assets in accordance with its transition and
rate stabilization plans. These regulatory assets total $250 million as of
March 31, 2005 and 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. Penn's net regulatory asset components
aggregate as net regulatory liabilities of approximately $27 million and $18
million included in Other Noncurrent Liabilities on the Consolidated Balance
Sheet as of March 31, 2005 and December 31, 2004,
respectively.





See Note 13 to the
consolidated financial statements for further details and a complete discussion
of regulatory matters in Ohio and Pennsylvania and a more detailed discussion of
reliability initiatives, including actions by the PPUC, that impact
Penn.





*Environmental
Matters*





OE accrues
environmental liabilities only when it concludes that it is probable that it has
an obligation for such costs and can reasonably determine the amount of such
costs. Unasserted claims are reflected in OE's determination of environmental
liabilities and are accrued in the period that they are both probable and
reasonably estimable.





*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 March 10, 2005, the EPA finalized the "Clean Air
Interstate Rule" covering a total of 28 states (including Ohio and Pennsylvania)
and the District of Columbia based on proposed findings that air emissions from
28 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. CAIR will require additional reductions of NO x and SO 2 emissions in two
phases (Phase I in 2009 for NO x , 2010 for
SO 2 and Phase II in
2015 for both NO x and SO 2 ). The OE Companies’
Ohio and Pennsylvania fossil-fuel generation facilities will be subject to the
caps on SO 2 and NO x emissions.
According to the EPA, SO 2 emissions will be
reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule,
with reductions reaching 73% (from 2003 levels) by 2015, capping SO 2 emissions in
affected states to just 2.5 million tons annually. NO x emissions will be
reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule,
with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional
NO x cap of 1.3 million
tons annually. The future cost of compliance with these regulations may be
substantial and will depend on how they are ultimately implemented by the states
in which the OE 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 March 14, 2005, the EPA
finalized a cap-and-trade program to reduce mercury emissions in two phases from
coal-fired power plants. Initially, mercury emissions will decline by 2010 as a
"co-benefit" from implementation of SO 2 and NO x emission caps under
the EPA's CAIR program. Phase II of the mercury cap-and-trade program will cap
nationwide mercury emissions from coal-fired power plants at 15 tons per year by
2018. The future cost of compliance with these regulations may be
substantial.





55





*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 (DOJ) 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. On March 18, 2005, OE and
Penn announced that they had reached a settlement with the EPA, the DOJ and
three states (Connecticut, New Jersey, and New York) that resolved all issues
related to the W. H. Sammis Plant New Source Review litigation. This settlement
agreement, which is in the form of a Consent Decree subject to a thirty-day
public comment period that ended on April 29, 2005 and final approval by the
District Court Judge, requires OE and Penn to reduce emissions from the W. H.
Sammis Plant and other plants through the installation of pollution control
devices requiring capital expenditures currently estimated to be $1.1 billion
(primarily in the 2008 to 2011 time period).The settlement agreement also
requires OE and Penn to spend up to $25 million towards environmentally
beneficial projects, which include wind energy purchase power agreements over a
20-year term. OE and Penn also agreed to pay a civil penalty of $8.5 million.
Results for the first quarter of 2005 include penalties payable by OE and Penn
of $7.8 million and $0.7 million, respectively. OE and Penn also accrued $9.2
million and $0.8 million, respectively, for cash contributions toward
environmentally beneficial projects during the first quarter of
2005.





*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 percent through
2012.


The OE Companies
cannot currently estimate the financial impact of climate change policies,
although the potential restrictions on CO 2 emissions could
require significant capital and other expenditures. However, the CO 2 emissions per KWH
of electricity generated by the OE Companies is lower than many regional
competitors due to the OE Companies' diversified generation sources which
include low or non-CO 2 emitting gas-fired
and nuclear generators.





FirstEnergy plans to
issue a report that will disclose the Companies’ environmental activities,
including their plans to respond to environmental requirements. FirstEnergy
expects to complete the report by December 1, 2005 and will post the report on
its web site, www.firstenergycorp.com .





*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.


See Note 12(B) to
the consolidated financial statements for further details and a complete
discussion of environmental matters.





*Other Legal
Proceedings*





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





56





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. The U.S. - Canada Power System Outage Task Force’s
final report in April 2004 on the outages 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 contained 46
"recommendations to prevent or minimize the scope of future blackouts."
Forty-five of those recommendations related to broad industry or policy matters
while one, including subparts, related to activities the Task Force recommended
be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the
causes of the August 14, 2003 power outages. FirstEnergy implemented
several initiatives, both prior to and since the August 14, 2003 power
outages, which were independently verified by NERC as complete in 2004 and were
consistent with these and other recommendations and collectively enhance the
reliability of its electric system. 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 completed in 2004 had a material effect on its
continuing 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 March 31, 2005 for any expenditures in excess
of those actually incurred through that date.


Three substantially
similar actions were filed in various Ohio State courts by plaintiffs seeking to
represent customers who allegedly suffered damages as a result of the
August 14, 2003 power outages. All three cases were dismissed for lack of
jurisdiction. One case was refiled on January 12, 2004 at the PUCO. The other
two cases were appealed. One case was dismissed and no further appeal was
sought. In the remaining case, the Court of Appeals on March 31, 2005
affirmed the trial court’s decision dismissing the case. It is not yet known
whether further appeal will be sought. 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 was
filed on August 25, 2004 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.




On August 12,
2004, the NRC notified FENOC that it would 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 OE Companies have a 35.24% interest. On April 4, 2005, the NRC held
a public forum to discuss FENOC’s performance at the Perry Nuclear Power Plant
as identified in the NRC's annual assessment letter to FENOC. Similar public
meetings are held with all nuclear power plant licensees following issuance by
the NRC of their annual assessments. According to the NRC, overall the Perry
Plant operated "in a manner that preserved public health and safety" and met all
cornerstone objectives although it remained under the heightened NRC oversight
since August 2004. During the public forum and in the annual assessment, the NRC
indicated that additional inspections will continue and that the plant must
improve performance to be removed from the Multiple/Repetitive Degraded
Cornerstone Column of the Action Matrix. If performance does not improve, the
NRC has a range of options under the Reactor Oversight Process from increased
oversight to possible impact to the plant’s operating authority. As a result,
these matters could have a material adverse effect on FirstEnergy's or its
subsidiaries' financial condition.





57





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 (OE has 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 the above matter, it could
have a material adverse effect on FirstEnergy's or its subsidiaries' financial
condition and results of operations.





See Note 12(C) to
the consolidated financial statements for further details and a complete
discussion of other legal proceedings.





**New
Accounting Standards and Interpretations**





*FIN 47, “Accounting for Conditional Asset Retirement
Obligations - an interpretation of FASB Statement No. 143”*





On March 30,
2005, the FASB issued this interpretation to clarify the scope and timing of
liability recognition for conditional asset retirement obligations. Under this
interpretation, companies are required to recognize a liability for the fair
value of an asset retirement obligation that is conditional on a future event,
if the fair value of the liability can be reasonably estimated. In instances
where there is insufficient information to estimate the liability, the
obligation is to be recognized in the first period in which sufficient
information becomes available to estimate its fair value. If the fair value
cannot be reasonably estimated, that fact and the reasons why must be disclosed.
This interpretation is effective no later than the end of fiscal years ending
after December 15, 2005. FirstEnergy is currently evaluating the effect
this standard will have 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, FirstEnergy will continue
to evaluate its investments as required by existing authoritative
guidance.








58


**THE
      CLEVELAND ELECTRIC ILLUMINATING
    COMPANY****CONSOLIDATED
      STATEMENTS OF INCOME AND COMPREHENSIVE
      INCOME****(Unaudited)******
    
    **Three
      Months Ended****March
      31,****2005**
    
    **2004****STATEMENTS
      OF INCOME**
    
    
    
    ***(In
      thousands)*****OPERATING
      REVENUES**
    
    
    
    
    $
    433,173
    
    $
    426,535**OPERATING
      EXPENSES AND TAXES:**Fuel
    
    
    
    
    
    18,327
    
    
    17,196Purchased
      power
    
    
    
    
    
    142,884
    
    
    134,677Nuclear
      operating costs
    
    
    
    
    
    58,727
    
    
    32,715Other
      operating costs
    
    
    
    
    
    63,573
    
    
    64,027Provision for
      depreciation
    
    
    
    
    
    31,115
    
    
    32,188Amortization
      of regulatory assets
    
    
    
    
    
    54,026
    
    
    48,068Deferral of
      new regulatory assets
    
    
    
    
    
    (25,288
    )
    
    (18,480
    )General
      taxes
    
    
    
    
    
    38,887
    
    
    38,818Income
      taxes
    
    
    
    
    
    4,877
    
    
    4,013Total
      operating expenses and taxes
    
    
    
    
    
    387,128
    
    
    353,222**OPERATING
      INCOME**
    
    
    
    
    
    46,045
    
    
    73,313**OTHER
      INCOME (net of income taxes)**
    
    
    
    
    
    4,304
    
    
    11,727**NET
      INTEREST CHARGES:**Interest on
      long-term debt
    
    
    
    
    
    27,952
    
    
    32,211Allowance for
      borrowed funds used during construction
    
    
    
    
    
    411
    
    
    (1,711
    )Other interest
      expense
    
    
    
    
    
    6,514
    
    
    6,065Net interest
      charges
    
    
    
    
    
    34,877
    
    
    36,565**NET
      INCOME**
    
    
    
    
    
    15,472
    
    
    48,475**PREFERRED
      STOCK DIVIDEND REQUIREMENTS**
    
    
    
    
    
    2,918
    
    
    1,744**EARNINGS
      ON COMMON STOCK**
    
    
    
    
    $
    12,554
    
    $
    46,731**STATEMENTS
      OF COMPREHENSIVE INCOME****NET
      INCOME**
    
    
    
    
    $
    15,472
    
    $
    48,475**OTHER
      COMPREHENSIVE INCOME (LOSS):**Unrealized
      gain (loss) on available for sale securities
    
    
    
    
    
    (1,221
    )
    
    8,048Income tax
      related to other comprehensive income
    
    
    
    
    
    504
    
    
    (3,296
    )Other
      comprehensive income (loss), net of tax
    
    
    
    
    
    (717
    )
    
    4,752**TOTAL
      COMPREHENSIVE INCOME**
    
    
    
    
    $
    14,755
    
    $
    53,227The preceding
      Notes to Consolidated Financial Statements as they relate to The Cleveland
      Electric Illuminating Company are an integralpart of these
      statements.
   59
  **THE
      CLEVELAND ELECTRIC ILLUMINATING
    COMPANY****CONSOLIDATED
      BALANCE SHEETS****(Unaudited)****March
      31,**
    
    **December
      31,****2005**
    
    **2004*****(In
      thousands)*****ASSETS****UTILITY
      PLANT:**In
      service
    
    
    
    
    $
    4,438,471
    
    $
    4,418,313Less -
      Accumulated provision for depreciation
    
    
    
    
    
    1,984,240
    
    
    1,961,7372,454,231
    
    
    2,456,576Construction
      work in progress-Electric
      plant
    
    
    
    
    
    86,276
    
    
    85,258Nuclear
      fuel
    
    
    
    
    
    39,655
    
    
    30,827125,931
    
    
    116,0852,580,162
    
    
    2,572,661**OTHER
      PROPERTY AND INVESTMENTS:**Investment in
      lessor notes
    
    
    
    
    
    564,175
    
    
    596,645Nuclear plant
      decommissioning trusts
    
    
    
    
    
    391,857
    
    
    383,875Long-term
      notes receivable from associated companies
    
    
    
    
    
    7,222
    
    
    97,489Other
    
    
    
    
    
    16,042
    
    
    17,001979,296
    
    
    1,095,010**CURRENT
      ASSETS:**Cash and cash
      equivalents
    
    
    
    
    
    207
    
    
    197Receivables-Customers
    
    
    
    
    
    14,233
    
    
    11,537Associated
      companies
    
    
    
    
    
    6,277
    
    
    33,414Other (less
      accumulated provisions of $207,000 and $293,000, respectively,for
      uncollectible accounts)
    
    
    
    
    
    92,336
    
    
    152,785Notes
      receivable from associated companies
    
    
    
    
    
    --
    
    
    521Materials and
      supplies, at average cost
    
    
    
    
    
    81,258
    
    
    58,922Prepayments
      and other
    
    
    
    
    
    1,509
    
    
    2,136195,820
    
    
    259,512**DEFERRED
      CHARGES:**Goodwill
    
    
    
    
    
    1,693,629
    
    
    1,693,629Regulatory
      assets
    
    
    
    
    
    925,473
    
    
    958,986Property
      taxes
    
    
    
    
    
    77,792
    
    
    77,792Other
    
    
    
    
    
    44,648
    
    
    32,8752,741,542
    
    
    2,763,282$
    6,496,820
    
    $
    6,690,465**CAPITALIZATION
      AND LIABILITIES****CAPITALIZATION:**Common
      stockholder's equity-Common stock,
      without par value, authorized 105,000,000 shares -79,590,689
      shares outstanding
    
    
    
    
    $
    1,281,962
    
    $
    1,281,962Accumulated
      other comprehensive income
    
    
    
    
    
    17,142
    
    
    17,859Retained
      earnings
    
    
    
    
    
    511,288
    
    
    553,740Total common
      stockholder's equity
    
    
    
    
    
    1,810,392
    
    
    1,853,561Preferred
      stock
    
    
    
    
    
    --
    
    
    96,404Long-term debt
      and other long-term obligations
    
    
    
    
    
    1,953,089
    
    
    1,970,1173,763,481
    
    
    3,920,082**CURRENT
      LIABILITIES:**Currently
      payable long-term debt
    
    
    
    
    
    81,382
    
    
    76,701Accounts
      payable-Associated
      companies
    
    
    
    
    
    191,057
    
    
    150,141Other
    
    
    
    
    
    7,593
    
    
    9,271Notes payable
      to associated companies
    
    
    
    
    
    470,732
    
    
    488,633Accrued
      taxes
    
    
    
    
    
    108,256
    
    
    129,454Accrued
      interest
    
    
    
    
    
    34,133
    
    
    22,102Lease market
      valuation liability
    
    
    
    
    
    60,200
    
    
    60,200Other
    
    
    
    
    
    32,312
    
    
    61,131985,665
    
    
    997,633**NONCURRENT
      LIABILITIES:**Accumulated
      deferred income taxes
    
    
    
    
    
    535,908
    
    
    540,211Accumulated
      deferred investment tax credits
    
    
    
    
    
    59,569
    
    
    60,901Asset
      retirement obligation
    
    
    
    
    
    276,627
    
    
    272,123Retirement
      benefits
    
    
    
    
    
    81,828
    
    
    82,306Lease market
      valuation liability
    
    
    
    
    
    653,200
    
    
    668,200Other
    
    
    
    
    
    140,542
    
    
    149,0091,747,674
    
    
    1,772,750**COMMITMENTS
      AND CONTINGENCIES (Note 12)**$
    6,496,820
    
    $
    6,690,465The preceding
      Notes to Consolidated Financial Statements as they relate to The Cleveland
      Electric Illuminating Company are an integral part of these balance
      sheets.
   60
   **THE
      CLEVELAND ELECTRIC ILLUMINATING
    COMPANY****CONSOLIDATED
      STATEMENTS OF CASH FLOWS****(Unaudited)******
    
    **Three
      Months Ended****March
      31,****2005**
    
    **2004*****(In
      thousands)*****CASH
      FLOWS FROM OPERATING ACTIVITIES:**Net
      income
    
    
    
    
    $
    15,472
    
    $
    48,475Adjustments to
      reconcile net income to net cash from operating
activities-Provision for
      depreciation
    
    
    
    
    
    31,115
    
    
    32,188Amortization
      of regulatory assets
    
    
    
    
    
    54,026
    
    
    48,068Deferral of
      new regulatory assets
    
    
    
    
    
    (25,288
    )
    
    (18,480
    )Nuclear fuel
      and capital lease amortization
    
    
    
    
    
    4,610
    
    
    5,107Amortization
      of electric service obligation
    
    
    
    
    
    (5,451
    )
    
    (4,723
    )Deferred rents
      and lease market valuation liability
    
    
    
    
    
    (53,469
    )
    
    (41,635
    )Deferred
      income taxes and investment tax credits, net
    
    
    
    
    
    (4,506
    )
    
    (4,039
    )Accrued
      retirement benefit obligations
    
    
    
    
    
    (478
    )
    
    5,732Accrued
      compensation, net
    
    
    
    
    
    (2,725
    )
    
    1,453Decrease
      (Increase) in operating assets-Receivables
    
    
    
    
    
    84,890
    
    
    143,766Materials and
      supplies
    
    
    
    
    
    (22,336
    )
    
    (2,355
    )Prepayments
      and other current assets
    
    
    
    
    
    627
    
    
    1,895Increase
      (Decrease) in operating liabilities-Accounts
      payable
    
    
    
    
    
    39,238
    
    
    22,387Accrued
      taxes
    
    
    
    
    
    (21,198
    )
    
    (67,926
    )Accrued
      interest
    
    
    
    
    
    12,031
    
    
    8,239Other
    
    
    
    
    
    (3,358
    )
    
    (29,788
    )Net cash
      provided from operating activities
    
    
    
    
    
    103,200
    
    
    148,364**CASH
      FLOWS FROM FINANCING ACTIVITIES:**New
      Financing-Long-term
      debt
    
    
    
    
    
    --
    
    
    80,967Redemptions
      and Repayments-Preferred
      stock
    
    
    
    
    
    (97,900
    )
    
    --Long-term
      debt
    
    
    
    
    
    (330
    )
    
    (7,985
    )Short-term
      borrowings, net
    
    
    
    
    
    (29,683
    )
    
    (182,167
    )Dividend
      Payments-Common
      stock
    
    
    
    
    
    (55,000
    )
    
    (55,000
    )Preferred
      stock
    
    
    
    
    
    (2,260
    )
    
    (1,744
    )Net cash used
      for financing activities
    
    
    
    
    
    (185,173
    )
    
    (165,929
    )**CASH
      FLOWS FROM INVESTING ACTIVITIES:**Property
      additions
    
    
    
    
    
    (33,683
    )
    
    (17,868
    )Loan
      repayments from (loans to) associated companies, net
    
    
    
    
    
    90,788
    
    
    (2,922
    )Investments in
      lessor notes
    
    
    
    
    
    32,470
    
    
    20,965Contributions
      to nuclear decommissioning trusts
    
    
    
    
    
    (7,256
    )
    
    (7,256
    )Other
    
    
    
    
    
    (336
    )
    
    64Net cash
      provided from (used for) investing activities
    
    
    
    
    
    81,983
    
    
    (7,017
    )Net increase
      (decrease) in cash and cash equivalents
    
    
    
    
    
    10
    
    
    (24,582
    )Cash and cash
      equivalents at beginning of period
    
    
    
    
    
    197
    
    
    24,782Cash and cash
      equivalents at end of period
    
    
    
    
    $
    207
    
    $
    200The preceding
      Notes to Consolidated Financial Statements as they relate to The Cleveland
      Electric Illuminating Company are an integral partof these
      statements.
   61


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





























To the Stockholders
and Board of


Directors of The
Cleveland Electric Illuminating Company:





We have reviewed the
accompanying consolidated balance sheet of The Cleveland Electric Illuminating
Company and its subsidiaries as of March 31, 2005, and the related
consolidated statements of income, comprehensive income and cash flows for each
of the three-month periods ended March 31, 2005 and 2004. These interim
financial statements are the responsibility of the Company’s
management.





We conducted our
review in accordance with the standards of the Public Company Accounting
Oversight Board (United States). A review of interim financial information
consists principally of applying analytical procedures and making inquiries of
persons responsible for financial and accounting matters. It is substantially
less in scope than an audit conducted in accordance with the standards of the
Public Company Accounting Oversight Board, the objective of which is the
expression of an opinion regarding the financial statements taken as a whole.
Accordingly, we do not express such an opinion.





Based on our review,
we are not aware of any material modifications that should be made to the
accompanying consolidated interim financial statements for them to be in
conformity with accounting principles generally accepted in the United States of
America.





We previously
audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheet as of
December 31, 2004, and the related consolidated statements of income,
capitalization, common stockholder’s equity, preferred stock, cash flows and
taxes for the year then ended, management’s assessment of the effectiveness of
the Company’s internal control over financial reporting as of December 31,
2004 and the effectiveness of the Company’s internal control over financial
reporting as of December 31, 2004; and in our report (which contained
references to the Company’s change in its method of accounting for asset
retirement obligations as of January 1, 2003 as discussed in Note 2(G) to
those consolidated financial statements and the Company’s change in its method
of accounting for the consolidation of variable interest entities as of
December 31, 2003 as discussed in Note 6 to those consolidated financial
statements) dated March 7, 2005, we expressed unqualified opinions thereon.
The consolidated financial statements and management’s assessment of the
effectiveness of internal control over financial reporting referred to above are
not presented herein. In our opinion, the information set forth in the
accompanying consolidated balance sheet information as of December 31,
2004, is fairly stated in all material respects in relation to the consolidated
balance sheet from which it has been derived.














PricewaterhouseCoopers
LLP


Cleveland,
Ohio


May 3,
2005





62





**THE
CLEVELAND ELECTRIC ILLUMINATING COMPANY**





**MANAGEMENT’S
DISCUSSION AND ANALYSIS OF**


**RESULTS OF
OPERATIONS AND FINANCIAL CONDITION**





CEI is a wholly
owned, electric utility subsidiary of FirstEnergy. CEI conducts business in
portions of Ohio, providing regulated electric distribution services. CEI also
provides generation services to those customers electing to retain CEI as their
power supplier. CEI provides power directly to alternative energy suppliers
under CEI’s transition plan. CEI has unbundled the price of electricity into its
component elements -- including generation, transmission, distribution and
transition charges. Power supply requirements of CEI are provided by FES -- an
affiliated company.





**Results of
Operations**


Earnings on common
stock in the first quarter of 2005 decreased to $13 million from $47 million in
the first quarter of 2004. This decrease resulted principally from higher
nuclear operating and purchased power costs, partially offset by higher
operating revenues.


Operating revenues
increased by $7 million or 1.6% in the first quarter of 2005 from the same
period in 2004. Higher revenues resulted principally from increased retail
generation sales revenue of $6 million (commercial - $1 million and industrial -
$5 million).





Retail generation
KWH sales declined slightly and were not materially affected by customer
shopping as generation services provided by alternative suppliers in CEI's
service area remained relatively constant in the first quarter of 2005 compared
to 2004. The industrial revenue increase was primarily due to higher unit prices
partially offset by the effect of a 1.8% KWH sales decrease. The increase in
commercial sector revenues was primarily due to a 3.3% KWH sales increase.
Residential retail generation revenues were nearly unchanged for the first
quarter of 2005 as compared to last year.





Wholesale sale
revenues showed a slight increase of $0.4 million while reflecting the effect of
a net 2.8% decrease in KWH sales. MSG wholesale sales to non-affiliated
customers increased by $8.2 million (38% KWH sales increase). Under its Ohio
transition plan, CEI is required to provide a low-cost generation power supply
to unaffiliated alternative suppliers (see Outlook - Regulatory Matters). The
MSG sales increase was partially offset by decreased sales to FES of $7.8
million (6.9% KWH decrease) due to less nuclear generation available for
sale.





Revenues from
distribution throughput decreased by $5 million in the first quarter of 2005
compared with the corresponding quarter in 2004. The decrease was due to lower
residential and industrial revenues ($3 million and $4 million, respectively)
reflecting lower composite unit prices and reduced distribution deliveries in
the first quarter of 2005. These impacts were partially offset by higher
commercial sector sales of $2 million resulting from increased distribution
deliveries partially offset by lower unit prices. Under the Ohio transition
plan, CEI provides incentives to customers to encourage switching to alternative
energy providers - $1 million of additional credits were provided to customers
in the first quarter of 2005 compared with 2004. These revenue reductions are
deferred for future recovery under CEI's transition plan and do not affect
current period earnings.





Other operating
revenues increased by $6 million in the first quarter of 2005 compared with
2004, primarily due to increased revenues from the sales of its customer
receivables (see Off-Balance Sheet Arrangements).





Changes in electric
generation sales and distribution deliveries in the first quarter of 2005 from
the first quarter of 2004 are summarized in the following table:





**Changes
      in KWH Sales****Increase
      (Decrease)**Electric
      Generation:Retail
    
    
    (0.6
    )%Wholesale
    
    
    (2.8
    )%**Total
      Electric Generation Sales**
    
    
    (1.8
    )%Distribution
      Deliveries:Residential
    
    
    (3.3
    )%Commercial
    
    
    5.5
    %Industrial
    
    
    (2.4
    )%**Total
      Distribution Deliveries**
    
    
    (0.7
    )%








63





*Operating
Expenses and Taxes*





Total operating
expenses and taxes increased by $34 million in the first quarter of 2005 from
the first quarter of 2004. The following table presents changes from the prior
year by expense category.








**Operating
      Expenses and Taxes - Changes*****(In
      millions)*****Increase
      (Decrease)**Fuel
      costs
    
    $
    1Purchased
      power costs
    
    
    8Nuclear
      operating costs
    
    
    26Provision for
      depreciation
    
    
    (1
    )Amortization
      of regulatory assets
    
    
    6Deferral of
      new regulatory assets
    
    
    (7
    )Income
      taxes
    
    
    1**Net
      increase in operating expenses and taxes**
    
    $
    34








Higher purchased
power costs in the first quarter of 2005, compared with the first quarter of
2004, reflected higher KWH purchased, partially offset by lower unit costs. The
increase in nuclear operating costs for the first quarter of 2005 compared to
the first quarter of 2004 was primarily due to a refueling outage (including an
unplanned extension) at the Perry nuclear plant and a mid-cycle inspection
outage at the Davis-Besse nuclear plant in the first quarter of 2005 and no
scheduled outages in the first quarter of 2004.





The decrease in
depreciation in the first quarter of 2005 compared with the first quarter of
2004 was attributable to revised estimated service life assumptions for fossil
generating plants. Higher amortization of regulatory assets in 2005 as compared
to 2004 was primarily due to increased amortization of transition regulatory
assets. Increases in the deferral of regulatory assets in 2005 from 2004
resulted from higher shopping incentive deferrals ($1 million) and deferred
interest on the shopping incentives ($5 million).





*Other
Income*





Other income
decreased by $7 million in the first quarter of 2005, compared with the first
quarter of 2004, primarily due to an increase in expenses related to the sales
of customer receivables and a $2 million potential NRC fine related to the
Davis-Besse Plant (see Outlook - Other Legal Proceedings).





*Net Interest
Charges*





Net interest charges
continued to trend lower, decreasing by $2 million in the first quarter of 2005
from the same quarter last year, reflecting the effects of redemptions and
refinancings of $281 million and $46 million, respectively, subsequent to the
first quarter of 2004.





*Preferred Stock
Dividend Requirements*





Preferred stock
dividend requirements increased by $1 million in the first quarter of 2005,
compared to the same period last year, due to premiums related to optional
preferred stock redemptions in the first quarter of 2005.





**Capital
Resources and Liquidity**





CEI’s cash
requirements in 2005 for operating expenses, construction expenditures,
scheduled debt maturities and preferred stock redemptions are expected to
be met without increasing net debt and preferred stock outstanding. Thereafter,
CEI expects to use a combination of cash from operations and funds from the
capital markets.





*Changes in Cash
Position*





As of March 31,
2005, CEI had $207,000 of cash and cash equivalents, compared with $197,000 as
of December 31, 2004. The major sources of changes in these balances are
summarized below.





64





*Cash Flows from
Operating Activities*





Cash provided by
operating activities during the first quarter of 2005, compared with the first
quarter of 2004, were as follows:





**Operating
      Cash Flows**
    
    **2005**
    
    **2004*****(In
      millions)***Cash earnings(1)
    
    $
    13
    
    $
    72Working
      capital and other
    
    
    90
    
    
    76Total
    
    $
    103
    
    $
    148





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





Cash earnings (in
the table above) are not a measure of performance calculated in accordance with
GAAP. CEI believes that cash earnings is a useful financial measure because it
provides investors and management with an additional means of evaluating its
cash-based operating performance. The following table reconciles cash earnings
with net income.


**Three
      Months Ended****March
      31,****Reconciliation
      of Cash Earnings**
    
    **2005**
    
    **2004*****(In
      millions)***Net Income
      (GAAP)
    
    $
    15
    
    $
    48Non-Cash
      Charges (Credits):Provision for
      depreciation
    
    
    31
    
    
    32Amortization
      of regulatory assets
    
    
    54
    
    
    48Deferral of
      new regulatory assets
    
    
    (25
    )
    
    (18
    )Nuclear fuel
      and capital lease amortization
    
    
    4
    
    
    5Amortization
      of electric service obligation
    
    
    (5
    )
    
    (4
    )Deferred rents
      and lease market valuation liability
    
    
    (53
    )
    
    (42
    )Deferred
      income taxes and investment tax credits, net
    
    
    (4
    )
    
    (4
    )Accrued
      retirement benefit obligations
    
    
    (1
    )
    
    6Accrued
      compensation, net
    
    
    (3
    )
    
    1**Cash
      earnings (Non-GAAP)**
    
    $
    13
    
    $
    72








The $59 million
decrease in cash earnings is described above and under "Results of Operations",
partially offset by a $14 million increase from working capital and other cash
flows. The largest factors contributing to the change in working capital and
other cash flows were changes in accrued taxes, accrued interest and accounts
payable, partially offset by changes in receivables.





*Cash Flows from
Financing Activities*




Net cash used for
financing activities increased $19 million in the first quarter of 2005 from the
first quarter of 2004. The increase in funds used for financing activities
resulted from $98 million of optional redemptions of preferred stock in the
first quarter of 2005, partially offset by a reduction in net debt
redemptions.





CEI had $207,000 of
cash and temporary investments and approximately $471 million of short-term
indebtedness as of March 31, 2005. CEI has obtained authorization from the
PUCO to incur short-term debt of up to $500 million (including the utility money
pool described below). CEI had the capability to issue $1.4 billion of
additional FMB on the basis of property additions and retired bonds under the
terms of its mortgage indenture. The issuance of FMB by CEI is subject to a
provision of its senior note indenture 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, this
provision would permit CEI to incur additional secured debt not otherwise
permitted by a specified exception of up to $565 million as of March 31,
2005. CEI has no restrictions on the issuance of preferred stock.





65




CEI has the ability
to borrow from its regulated affiliates and FirstEnergy to meet its short-term
working capital requirements. FESC administers this money pool and tracks
surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving
a loan under the money pool agreements must repay the principal amount, together
with accrued interest, within 364 days of borrowing the funds. The rate of
interest is the same for each company receiving a loan from the pool and is
based on the average cost of funds available through the pool. The average
interest rate for borrowings in the first quarter of 2005 was
2.66%.





CEI’s access to
capital markets and costs of financing are dependent on the ratings of its
securities and the securities of FirstEnergy. The ratings outlook from the
rating agencies on all such securities is stable.





On March 18,
2005, S&P stated that FirstEnergy’s Sammis NSR settlement was a very
favorable step for FirstEnergy, although it would not immediately affect
FirstEnergy’s ratings or outlook. S&P noted that it continues to monitor the
refueling outage at the Perry nuclear plant, which includes a detailed
inspection by the NRC, and that if FirstEnergy should exit the outage
without significant negative findings or delays the ratings outlook would be
revised to positive.





On March 14,
2005, CEI redeemed all 500,000 outstanding shares of its Serial Preferred Stock,
$7.40 Series A at a price of $101 per share plus accrued dividends to the date
of the redemption. Also on March 14, 2005, CEI redeemed all 474,000
outstanding shares of its Serial Preferred Stock, Adjustable Rate Series L at a
price of $100 per share plus accrued dividends to the date of the
redemption.





On April 20,
2005, Beaver County Industrial Development Authority pollution control bonds
aggregating $53.9 million were refunded. The new bonds were issued in a Dutch
Auction interest rate mode, insured with municipal bond insurance and secured by
FMB.





On June 1, 2005, CEI intends to redeem all of its 40,000 outstanding
shares of $7.35 Series C preferred stock at $101.00 per share, plus accrued
dividends to the date of redemption.





*Cash Flows from
Investing Activities*





Net cash provided
from investing activities was $82 million in the first quarter of 2005 compared
to cash used for investing activities of $7 million in the first quarter of
2004. The change was primarily due to increased loan payments received from
associated companies, partially offset by higher property
additions.





During the remaining
three quarters of 2005, capital requirements for property additions are expected
to be about $85 million, including $1 million for nuclear fuel. CEI has
additional requirements of approximately $1 million to meet sinking fund
requirements for preferred stock during the remainder of 2005. These cash
requirements are expected to be satisfied from internal cash and short-term
credit arrangements.





CEI’s capital
spending for the period 2005-2007 is expected to be about $368 million
(excluding nuclear fuel) of which approximately $108 million applies to 2005.
Investments for additional nuclear fuel during the 2005-2007 period are
estimated to be approximately $75 million, of which about $10 million applies to
2005. During the same periods, CEI’s nuclear fuel investments are expected to be
reduced by approximately $90 million and $27 million, respectively, as the
nuclear fuel is consumed.





**Off-Balance
Sheet Arrangements**


Obligations not
included on CEI’s Consolidated Balance Sheet primarily consist of sale and
leaseback arrangements involving the Bruce Mansfield Plant. As of March 31,
2005, the present value of these operating lease commitments, net of trust
investments, total $99 million.


CEI sells
substantially all of its retail customer receivables to CFC, its wholly owned
subsidiary. CFC subsequently transfers the receivables to a trust (a "qualified
special purpose entity" under SFAS 140) under an asset-backed securitization
agreement. This arrangement provided $94 million of off-balance sheet financing
as of March 31, 2005.





**Equity
Price Risk**


Included in CEI’s
nuclear decommissioning trust investments are marketable equity securities
carried at their market value of approximately $249 million and $242 million as
of March 31, 2005 and December 31, 2004, respectively. A hypothetical
10% decrease in prices quoted by stock exchanges would result in a $25 million
reduction in fair value as of March 31, 2005.


66





**Outlook**





The electric
industry continues to transition to a more competitive environment and all of
CEI's customers can select alternative energy suppliers. CEI continues to
deliver power to residential homes and businesses through its existing
distribution system, which remains regulated. Customer rates have been
restructured into separate components to support customer choice. CEI has 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 CEI's customers elects to obtain power from an alternative supplier, CEI
reduces the customer's bill with a "generation shopping credit," based on the
generation component (plus an incentive), and the customer receives a generation
charge from the alternative supplier. CEI has continuing PLR responsibility to
its franchise customers through December 31, 2005.








As part of CEI's
transition plan, it is obligated to supply electricity to customers who do not
choose an alternative supplier. CEI is also required to provide 400 MW of low
cost supply to unaffiliated alternative suppliers who serve customers within its
service area. FES acts as an alternate supplier for a portion of the load in
CEI's franchise area.





CEI's revised Rate
Stabilization Plan extends current generation prices through 2008, ensuring
adequate generation supply at stabilized prices, and continues CEI'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 2008 to as late as mid-2009;





·
    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 require CEI to undertake, no more often than annually, a similar
competitive bid process to secure generation for the years 2007 and 2008. Any
acceptance of future competitive bid results would terminate the Rate
Stabilization Plan pricing, but not the related approved accounting, and not
until twelve months after the PUCO authorizes such termination.





On December 30,
2004, CEI filed an application with the PUCO seeking tariff adjustments to
recover increases of approximately $16 million in transmission and ancillary
service costs beginning January 1, 2006. CEI 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.





On
September 16, 2004, the FERC issued an order that imposed additional
obligations on CEI under certain pre-Open Access transmission contracts among
CEI and the cities of Cleveland and Painesville, Ohio. Under the FERC's
decision, CEI may be responsible for a portion of new energy market charges
imposed by MISO when its energy markets begin in the spring of 2005. CEI filed
for rehearing of the order from the FERC on October 18, 2004. On
April 15, 2005, FERC issued an order on rehearing that "carves out" these
contracts from the MISO Day 2 market. While the order on rehearing is favorable
to CEI, the impact of the FERC decision on CEI is dependent upon many factors,
including the arrangements made by the cities for transmission service and
MISO's ability to administer the contracts. Accordingly, the impact of this
decision cannot be determined at this time.





67




Regulatory assets
are costs which have been authorized by the PUCO and the FERC for recovery from
customers in future periods and, without such authorization, would have been
charged to income when incurred. CEI's regulatory assets as of March 31,
2005 and December 2004 were $0.9 billion and $1.0 billion, respectively. CEI is
deferring customer shopping incentives and interest costs as new regulatory
assets in accordance with its transition and rate stabilization plans. These
regulatory assets total $320 million as of March 31, 2005 and 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.





See Note 13 to the
consolidated financial statements for further details and a complete discussion
of regulatory matters in Ohio.





*Environmental
Matters*





CEI accrues
environmental liabilities only when it concludes that it is probable that it has
an obligation for such costs and can reasonably determine the amount of such
costs. Unasserted claims are reflected in CEI's determination of environmental
liabilities and are accrued in the period that they are both probable and
reasonably estimable.





*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 March 10, 2005, the EPA finalized the "Clean Air
Interstate Rule" covering a total of 28 states (including Ohio and Pennsylvania)
and the District of Columbia based on proposed findings that air emissions from
28 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. CAIR will require additional reductions of NO x and SO 2 emissions in two
phases (Phase I in 2009 for NO x , 2010 for
SO 2 and Phase II in
2015 for both NO x and SO 2 ). CEI's Ohio and
Pennsylvania fossil-fuel generation facilities will be subject to the caps on
SO 2 and NO x emissions.
According to the EPA, SO 2 emissions will be
reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule,
with reductions reaching 73% (from 2003 levels) by 2015, capping SO 2 emissions in
affected states to just 2.5 million tons annually. NO x emissions will be
reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule,
with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional
NO x cap of 1.3 million
tons annually. The future cost of compliance with these regulations may be
substantial and will depend on how they are ultimately implemented by the states
in which CEI operates affected facilities.


*Mercury
Emissions*




In December 2000,
the EPA announced it would proceed with the development of regulations regarding
hazardous air pollutants from electric power plants, identifying mercury as the
hazardous air pollutant of greatest concern. On March 14, 2005, the EPA
finalized a cap-and-trade program to reduce mercury emissions in two phases from
coal-fired power plants. Initially, mercury emissions will decline by 2010 as a
"co-benefit" from implementation of SO 2 and NO x emission caps under
the EPA's CAIR program. Phase II of the mercury cap-and-trade program will cap
nationwide mercury emissions from coal-fired power plants at 15 tons per year by
2018. The future cost of compliance with these regulations may be
substantial.





*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 percent through
2012.


CEI cannot currently
estimate the financial impact of climate change policies, although the potential
restrictions on CO 2 emissions could
require significant capital and other expenditures. However, the CO 2 emissions per KWH
of electricity generated by CEI is lower than many regional competitors due to
CEI's diversified generation sources which include low or non-CO 2 emitting gas-fired
and nuclear generators.





68





FirstEnergy plans to
issue a report that will disclose the Companies’ environmental activities,
including their plans to respond to environmental requirements. FirstEnergy
expects to complete the report by December 1, 2005 and will post the report
on its web site, www.firstenergycorp.com .


*Regulation of
Hazardous Waste*





CEI has been named a
PRP at waste disposal sites, which may require cleanup under the Comprehensive
Environmental Response, Compensation and Liability Act of 1980. Allegations of
disposal of hazardous substances at historical sites and the liability involved
are often unsubstantiated and subject to dispute; however, federal law provides
that all PRPs for a particular site are liable on a joint and several basis.
Therefore, environmental liabilities that are considered probable have been
recognized on the Consolidated Balance Sheet as of March 31, 2005, based on
estimates of the total costs of cleanup, CEI's proportionate responsibility for
such costs and the financial ability of other nonaffiliated entities to pay.
Included in Current Liabilities are accrued liabilities aggregating
approximately $2.3 million as of March 31, 2005.





See Note 12(B) to
the consolidated financial statements for further details and a complete
discussion of environmental matters.





*Other Legal
Proceedings*





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





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. The U.S. - Canada Power System Outage Task Force’s
final report in April 2004 on the outages 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 contained 46
"recommendations to prevent or minimize the scope of future blackouts."
Forty-five of those recommendations related to broad industry or policy matters
while one, including subparts, related to activities the Task Force recommended
be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the
causes of the August 14, 2003 power outages. FirstEnergy implemented
several initiatives, both prior to and since the August 14, 2003 power
outages, which were independently verified by NERC as complete in 2004 and were
consistent with these and other recommendations and collectively enhance the
reliability of its electric system. 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 completed in 2004 had a material effect on its
continuing 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 March 31, 2005 for any expenditures in excess
of those actually incurred through that date.





Three substantially
similar actions were filed in various Ohio State courts by plaintiffs seeking to
represent customers who allegedly suffered damages as a result of the
August 14, 2003 power outages. All three cases were dismissed for lack of
jurisdiction. One case was refiled on January 12, 2004 at the PUCO. The other
two cases were appealed. One case was dismissed and no further appeal was
sought. In the remaining case, the Court of Appeals on March 31, 2005
affirmed the trial court’s decision dismissing the case. It is not yet known
whether further appeal will be sought. 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.





69




One complaint was
filed on August 25, 2004 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.





FENOC received a
subpoena in late 2003 from a grand jury sitting in the United States District
Court for the Northern District of Ohio, Eastern Division requesting the
production of certain documents and records relating to the inspection and
maintenance of the reactor vessel head at the Davis-Besse Nuclear Power Station,
in which CEI has a 51.38% interest. On December 10, 2004, FirstEnergy
received a letter from the United States Attorney's Office stating that FENOC is
a target of the federal grand jury investigation into alleged false statements
made to the NRC in the Fall of 2001 in response to NRC Bulletin 2001-01. The
letter also said that the designation of FENOC as a target indicates that, in
the view of the prosecutors assigned to the matter, it is likely that federal
charges will be returned against FENOC by the grand jury. On February 10,
2005, FENOC received an additional subpoena for documents related to root cause
reports regarding reactor head degradation and the assessment of reactor head
management issues at Davis-Besse.





On April 21,
2005, the NRC issued a NOV and proposed a $5.45 million civil penalty related to
the degradation of the Davis-Besse reactor vessel head described above. Under
the NRC’s letter, FENOC has ninety days to respond to this NOV. CEI has
accrued the remaining liability for its share of the proposed fine
of $1.8 million during the first quarter of 2005.





If it were ultimately determined that FirstEnergy or its subsidiaries has legal
liability based on the Davis-Besse head degradation, it could have a material
adverse effect on FirstEnergy's or its subsidiaries' financial condition and
results of operations.





On August 12,
2004, the NRC notified FENOC that it would 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 CEI has a 44.85% interest. On April 4, 2005, the NRC held a public
forum to discuss FENOC’s performance at the Perry Nuclear Power Plant as
identified in the NRC's annual assessment letter to FENOC. Similar public
meetings are held with all nuclear power plant licensees following issuance by
the NRC of their annual assessments. According to the NRC, overall the Perry
Plant operated "in a manner that preserved public health and safety" and met all
cornerstone objectives although it remained under the heightened NRC oversight
since August 2004. During the public forum and in the annual assessment, the NRC
indicated that additional inspections will continue and that the plant must
improve performance to be removed from the Multiple/Repetitive Degraded
Cornerstone Column of the Action Matrix. If performance does not improve, the
NRC has a range of options under the Reactor Oversight Process from increased
oversight to possible impact to the plant’s 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 CEI, and the Davis-Besse extended outage have become the subject
of a formal order of investigation. The SEC's formal order of investigation also
encompasses issues raised during the SEC's examination of FirstEnergy and the
Companies under the PUHCA. Concurrent with this notification, FirstEnergy
received a subpoena asking for background documents and documents related to the
restatements and Davis-Besse issues. On December 30, 2004, FirstEnergy
received a second subpoena asking for documents relating to issues raised during
the SEC's PUHCA examination. FirstEnergy has cooperated fully with the informal
inquiry and will continue to do so with the formal investigation.





If it were
ultimately determined that FirstEnergy or its subsidiaries have legal liability
or are otherwise made subject to liability based on the above matters, it could
have a material adverse effect on FirstEnergy's or its subsidiaries' financial
condition and results of operations.





See Note 12(C) to
the consolidated financial statements for further details and a complete
discussion of other legal proceedings.





70





**New
Accounting Standards and Interpretations**





*FIN 47, “Accounting for Conditional Asset Retirement
Obligations - an interpretation of FASB Statement No. 143”*





On March 30,
2005, the FASB issued this interpretation to clarify the scope and timing of
liability recognition for conditional asset retirement obligations. Under this
interpretation, companies are required to recognize a liability for the fair
value of an asset retirement obligation that is conditional on a future event,
if the fair value of the liability can be reasonably estimated. In instances
where there is insufficient information to estimate the liability, the
obligation is to be recognized in the first period in which sufficient
information becomes available to estimate its fair value. If the fair value
cannot be reasonably estimated, that fact and the reasons why must be disclosed.
This interpretation is effective no later than the end of fiscal years ending
after December 15, 2005. FirstEnergy is currently evaluating the effect
this standard will have 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, FirstEnergy will continue
to evaluate its investments as required by existing authoritative
guidance.








71





**THE
      TOLEDO EDISON COMPANY****CONSOLIDATED
      STATEMENTS OF INCOME AND COMPREHENSIVE
      INCOME****(Unaudited)******
    
    **Three
      Months Ended****March
      31,****2005**
    
    **2004****STATEMENTS
      OF INCOME**
    
    
    
    ***(In
      thousands)*****OPERATING
      REVENUES**
    
    
    
    
    $
    241,755
    
    $
    235,398**OPERATING
      EXPENSES AND TAXES:**Fuel
    
    
    
    
    
    12,569
    
    
    10,214Purchased
      power
    
    
    
    
    
    80,156
    
    
    82,408Nuclear
      operating costs
    
    
    
    
    
    59,163
    
    
    42,692Other
      operating costs
    
    
    
    
    
    34,348
    
    
    36,208Provision for
      depreciation
    
    
    
    
    
    14,680
    
    
    14,053Amortization
      of regulatory assets
    
    
    
    
    
    34,865
    
    
    33,666Deferral of
      new regulatory assets
    
    
    
    
    
    (9,424
    )
    
    (7,030
    )General
      taxes
    
    
    
    
    
    14,181
    
    
    14,300Income tax
      benefit
    
    
    
    
    
    (3,968
    )
    
    (1,578
    )Total
      operating expenses and taxes
    
    
    
    
    
    236,570
    
    
    224,933**OPERATING
      INCOME**
    
    
    
    
    
    5,185
    
    
    10,465**OTHER
      INCOME (net of income taxes)**
    
    
    
    
    
    2,659
    
    
    5,833**NET
      INTEREST CHARGES:**Interest on
      long-term debt
    
    
    
    
    
    4,220
    
    
    9,461Allowance for
      borrowed funds used during construction
    
    
    
    
    
    443
    
    
    (1,400
    )Other interest
      expense
    
    
    
    
    
    2,816
    
    
    706Net interest
      charges
    
    
    
    
    
    7,479
    
    
    8,767**NET
      INCOME**
    
    
    
    
    
    365
    
    
    7,531**PREFERRED
      STOCK DIVIDEND REQUIREMENTS**
    
    
    
    
    
    2,211
    
    
    2,211**EARNINGS
      (LOSS) APPLICABLE TO COMMON STOCK**
    
    
    
    
    $
    (1,846
    )
    $
    5,320**STATEMENTS
      OF COMPREHENSIVE INCOME****NET
      INCOME**
    
    
    
    
    
    365
    
    
    7,531**OTHER
      COMPREHENSIVE INCOME (LOSS):**Unrealized
      gain (loss) on available for sale securities
    
    
    
    
    
    (1,683
    )
    
    5,682Income tax
      related to other comprehensive income
    
    
    
    
    
    695
    
    
    (2,331
    )Other
      comprehensive income (loss), net of tax
    
    
    
    
    
    (988
    )
    
    3,351**TOTAL
      COMPREHENSIVE INCOME (LOSS)**
    
    
    
    
    $
    (623
    )
    $
    10,882The preceding
      Notes to Consolidated Financial Statements as they relate to The Toledo
      Edison Company are an integral part of these
      statements.
    72
  **THE
      TOLEDO EDISON COMPANY****CONSOLIDATED
      BALANCE SHEETS****(Unaudited)****March
      31,**
    
    **December
      31,****2005**
    
    **2004*****(In
      thousands)*****ASSETS****UTILITY
      PLANT:**In
      service
    
    
    
    
    $
    1,857,720
    
    $
    1,856,478Less -
      Accumulated provision for depreciation
    
    
    
    
    
    789,915
    
    
    778,8641,067,805
    
    
    1,077,614Construction
      work in progress-Electric
      plant
    
    
    
    
    
    66,405
    
    
    58,535Nuclear
      fuel
    
    
    
    
    
    22,634
    
    
    15,99889,039
    
    
    74,5331,156,844
    
    
    1,152,147**OTHER
      PROPERTY AND INVESTMENTS:**Investment in
      lessor notes
    
    
    
    
    
    178,764
    
    
    190,692Nuclear plant
      decommissioning trusts
    
    
    
    
    
    305,046
    
    
    297,803Long-term
      notes receivable from associated companies
    
    
    
    
    
    40,002
    
    
    39,975Other
    
    
    
    
    
    1,835
    
    
    2,031525,647
    
    
    530,501**CURRENT
      ASSETS:**Cash and cash
      equivalents
    
    
    
    
    
    15
    
    
    15Receivables-Customers
    
    
    
    
    
    6,443
    
    
    4,858Associated
      companies
    
    
    
    
    
    12,180
    
    
    36,570Other
    
    
    
    
    
    4,138
    
    
    3,842Notes
      receivable from associated companies
    
    
    
    
    
    137,266
    
    
    135,683Materials and
      supplies, at average cost
    
    
    
    
    
    46,769
    
    
    40,280Prepayments
      and other
    
    
    
    
    
    1,206
    
    
    1,150208,017
    
    
    222,398**DEFERRED
      CHARGES:**Goodwill
    
    
    
    
    
    504,522
    
    
    504,522Regulatory
      assets
    
    
    
    
    
    349,297
    
    
    374,814Property
      taxes
    
    
    
    
    
    24,100
    
    
    24,100Other
    
    
    
    
    
    43,312
    
    
    25,424921,231
    
    
    928,860$
    2,811,739
    
    $
    2,833,906**CAPITALIZATION
      AND LIABILITIES****CAPITALIZATION:**Common
      stockholder's equity-Common stock,
      $5 par value, authorized 60,000,000 shares -39,133,887
      shares outstanding
    
    
    
    
    $
    195,670
    
    $
    195,670Other paid-in
      capital
    
    
    
    
    
    428,559
    
    
    428,559Accumulated
      other comprehensive income
    
    
    
    
    
    19,051
    
    
    20,039Retained
      earnings
    
    
    
    
    
    189,213
    
    
    191,059Total common
      stockholder's equity
    
    
    
    
    
    832,493
    
    
    835,327Preferred
      stock
    
    
    
    
    
    126,000
    
    
    126,000Long-term debt
    
    
    
    
    
    300,131
    
    
    300,2991,258,624
    
    
    1,261,626**CURRENT
      LIABILITIES:**Currently
      payable long-term debt
    
    
    
    
    
    90,950
    
    
    90,950Accounts
      payable-Associated
      companies
    
    
    
    
    
    116,930
    
    
    110,047Other
    
    
    
    
    
    2,299
    
    
    2,247Notes payable
      to associated companies
    
    
    
    
    
    394,761
    
    
    429,517Accrued
      taxes
    
    
    
    
    
    31,695
    
    
    46,957Lease market
      valuation liability
    
    
    
    
    
    24,600
    
    
    24,600Other
    
    
    
    
    
    80,005
    
    
    53,055741,240
    
    
    757,373**NONCURRENT
      LIABILITIES:**Accumulated
      deferred income taxes
    
    
    
    
    
    221,759
    
    
    221,950Accumulated
      deferred investment tax credits
    
    
    
    
    
    24,562
    
    
    25,102Retirement
      benefits
    
    
    
    
    
    39,838
    
    
    39,227Asset
      retirement obligation
    
    
    
    
    
    197,564
    
    
    194,315Lease market
      valuation liability
    
    
    
    
    
    261,850
    
    
    268,000Other
    
    
    
    
    
    66,302
    
    
    66,313811,875
    
    
    814,907**COMMITMENTS
      AND CONTINGENCIES (Note 12)**$
    2,811,739
    
    $
    2,833,906The preceding
      Notes to Consolidated Financial Statements as they relate to The Toledo
      Edison Company are an integral part of these balance
    sheets.
   73
   **THE
      TOLEDO EDISON COMPANY****CONSOLIDATED
      STATEMENTS OF CASH FLOWS****(Unaudited)****Three
      Months Ended****March
      31,****2005**
    
    **2004*****(In
      thousands)*****CASH
      FLOWS FROM OPERATING ACTIVITIES:**Net
      income
    
    
    
    
    $
    365
    
    $
    7,531Adjustments to
      reconcile net income to net cash from operating
activities-Provision for
      depreciation
    
    
    
    
    
    14,680
    
    
    14,053Amortization
      of regulatory assets
    
    
    
    
    
    34,865
    
    
    33,666Deferral of
      new regulatory assets
    
    
    
    
    
    (9,424
    )
    
    (7,030
    )Nuclear fuel
      and capital lease amortization
    
    
    
    
    
    4,868
    
    
    5,506Deferred rents
      and lease market valuation liability
    
    
    
    
    
    (15,224
    )
    
    (7,692
    )Deferred
      income taxes and investment tax credits, net
    
    
    
    
    
    (1,387
    )
    
    (2,031
    )Accrued
      retirement benefit obligations
    
    
    
    
    
    611
    
    
    2,285Accrued
      compensation, net
    
    
    
    
    
    (1,265
    )
    
    (733
    )Decrease
      (Increase) in operating assets:Receivables
    
    
    
    
    
    41,475
    
    
    20,035Materials and
      supplies
    
    
    
    
    
    (6,489
    )
    
    (1,434
    )Prepayments
      and other current assets
    
    
    
    
    
    (56
    )
    
    3,384Increase
      (Decrease) in operating liabilities:Accounts
      payable
    
    
    
    
    
    6,935
    
    
    (6,074
    )Accrued
      taxes
    
    
    
    
    
    (15,262
    )
    
    (14,085
    )Accrued
      interest
    
    
    
    
    
    853
    
    
    (2,280
    )Other
    
    
    
    
    
    (1,989
    )
    
    (8,147
    )Net cash
      provided from operating activities
    
    
    
    
    
    53,556
    
    
    36,954**CASH
      FLOWS FROM FINANCING ACTIVITIES:**New
      Financing-Long-term
      debt
    
    
    
    
    
    --
    
    
    73,000Redemptions
      and Repayments-Long-term
      debt
    
    
    
    
    
    --
    
    
    (15,000
    )Short-term
      borrowings, net
    
    
    
    
    
    (34,993
    )
    
    (93,299
    )Dividend
      Payments-Preferred
      stock
    
    
    
    
    
    (2,211
    )
    
    (2,211
    )Net cash used
      for financing activities
    
    
    
    
    
    (37,204
    )
    
    (37,510
    )**CASH
      FLOWS FROM INVESTING ACTIVITIES:**Property
      additions
    
    
    
    
    
    (17,919
    )
    
    (8,440
    )Loan
      repayments from (loans to) associated companies, net
    
    
    
    
    
    (1,610
    )
    
    2,606Investments in
      lessor notes
    
    
    
    
    
    11,928
    
    
    10,280Contributions
      to nuclear decommissioning trusts
    
    
    
    
    
    (7,135
    )
    
    (7,135
    )Other
    
    
    
    
    
    (1,616
    )
    
    1,024Net cash used
      for investing activities
    
    
    
    
    
    (16,352
    )
    
    (1,665
    )Net change in
      cash and cash equivalents
    
    
    
    
    
    --
    
    
    (2,221
    )Cash and cash
      equivalents at beginning of period
    
    
    
    
    
    15
    
    
    2,237Cash and cash
      equivalents at end of period
    
    
    
    
    $
    15
    
    $
    16The preceding
      Notes to Consolidated Financial Statements as they relate to The Toledo
      Edison Company are an integral part of these
      statements.
   74


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





























To the Stockholders
and Board of


Directors of The
Toledo Edison Company:





We have reviewed the
accompanying consolidated balance sheet of The Toledo Edison Company and its
subsidiary as of March 31, 2005, and the related consolidated statements of
income, comprehensive income and cash flows for each of the three-month periods
ended March 31, 2005 and 2004. These interim financial statements are the
responsibility of the Company’s management.





We conducted our
review in accordance with the standards of the Public Company Accounting
Oversight Board (United States). A review of interim financial information
consists principally of applying analytical procedures and making inquiries of
persons responsible for financial and accounting matters. It is substantially
less in scope than an audit conducted in accordance with the standards of the
Public Company Accounting Oversight Board, the objective of which is the
expression of an opinion regarding the financial statements taken as a whole.
Accordingly, we do not express such an opinion.





Based on our review,
we are not aware of any material modifications that should be made to the
accompanying consolidated interim financial statements for them to be in
conformity with accounting principles generally accepted in the United States of
America.





We previously
audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheet as of
December 31, 2004, and the related consolidated statements of income,
capitalization, common stockholder’s equity, preferred stock, cash flows and
taxes for the year then ended, management’s assessment of the effectiveness of
the Company’s internal control over financial reporting as of December 31,
2004 and the effectiveness of the Company’s internal control over financial
reporting as of December 31, 2004; and in our report (which contained
references to the Company’s change in its method of accounting for asset
retirement obligations as of January 1, 2003 as discussed in Note 2(G) to
those consolidated financial statements and the Company’s change in its method
of accounting for the consolidation of variable interest entities as of
December 31, 2003 as discussed in Note 6 to those consolidated financial
statements) dated March 7, 2005, we expressed unqualified opinions thereon. The
consolidated financial statements and management’s assessment of the
effectiveness of internal control over financial reporting referred to above are
not presented herein. In our opinion, the information set forth in the
accompanying consolidated balance sheet information as of December 31,
2004, is fairly stated in all material respects in relation to the consolidated
balance sheet from which it has been derived.














PricewaterhouseCoopers
LLP


Cleveland,
Ohio


May 3,
2005





75





**THE TOLEDO
EDISON COMPANY**





**MANAGEMENT’S
DISCUSSION AND ANALYSIS OF**


**RESULTS OF
OPERATIONS AND FINANCIAL CONDITION**








TE is a wholly owned
electric utility subsidiary of FirstEnergy. TE conducts business in northwestern
Ohio, providing regulated electric distribution services. TE also provides
generation services to those customers electing to retain TE as their power
supplier. TE provides power directly to some alternative energy suppliers under
TE’s transition plan. TE has unbundled the price of electricity into its
component elements - including generation, transmission, distribution and
transition charges. TE’s power supply requirements are provided by FES - an
affiliated company.


**Results
of Operations**





Earnings applicable
to common stock in the first quarter of 2005 decreased to a loss of $2 million
from earnings of $5 million in the first quarter of 2004. This decrease resulted
primarily from higher nuclear operating costs, partially offset by higher
operating revenues and lower financing costs.





Operating revenues
increased by $6 million or 2.7% in the first quarter of 2005 from the same
period of 2004. Higher revenues resulted principally from increased retail
generation sales revenues of $10 million (industrial - $9 million and commercial
- $1 million) and wholesale sales (primarily to FES) of $4 million, partially
offset by a $7 million decrease in distribution revenues.





The industrial
generation revenue increase was primarily due to higher unit prices and a 1.6%
KWH sales increase. The increase in commercial sector revenues was principally
due to a 6.1% KWH sales increase. Residential retail generation
revenues were nearly unchanged for the first quarter of 2005 as compared to
last year due to higher unit prices offsetting the effect of a 4.5% KWH sales
decrease. The increased commercial volume sales partially reflected the effect
of lower customer shopping. Generation services provided to commercial customers
by alternative suppliers as a percent of total commercial sales deliveries in
TE's franchise area decreased by nearly one percentage point. The level of
shopping in the industrial sector was relatively unchanged. The residential
sales decrease resulted from an increase in residential shopping of 1.7
percentage points. Higher wholesale revenues reflected the effect of increased
nuclear generation available for sale to FES.





Revenues from
distribution throughput decreased by $7 million in the first quarter of 2005
from the corresponding quarter of 2004. The decrease was due to lower industrial
and residential revenues ($7 million and $1 million), principally due to lower
composite unit prices. The impact of lower residential KWH sales contributed to
the decrease while higher industrial sales partially offset the lower industrial
sector unit prices. These revenue decreases were partially offset by a $1
million commercial revenue increase that resulted from a 4.2% sales volume
increase partially offset by lower composite unit prices.





Under the Ohio
transition plan, TE provides incentives to customers to encourage switching to
alternative energy providers. TE’s revenues were reduced by $0.5 million for
additional credits in the first quarter of 2005, compared with the same period
of 2004. These revenue reductions are deferred for future recovery under TE’s
transition plan and do not affect current period earnings (see Regulatory
Matters below).





Changes in electric
generation sales and distribution deliveries in the first quarter of 2005 from
the first quarter of 2004, are summarized in the following table:





**Changes
      in KWH Sales****Increase
      (Decrease)**Electric
      Generation:Retail
    
    
    1.2
    %Wholesale
    
    
    18.5
    %**Total
      Electric Generation Sales**
    
    
    **9.2**
    **%**Distribution
      Deliveries:Residential
    
    
    (1.7
    )%Commercial
    
    
    4.2
    %Industrial
    
    
    2.0
    %**Total
      Distribution Deliveries**
    
    
    **1.7**
    **%**








76





*Operating
Expenses and Taxes*





Total operating
expenses and taxes increased by $12 million in the first quarter of 2005 from
the same quarter of 2004. The following table presents changes from the prior
year by expense category.








**Operating
      Expenses and Taxes - Changes*****Increase
      (Decrease)***
    
    ***(In
      millions)***Fuel
      costs
    
    $
    2Purchased
      power costs
    
    
    (2
    )Nuclear
      operating costs
    
    
    17Other
      operating costs
    
    
    (2
    )Provision for
      depreciation
    
    
    1Amortization
      of regulatory assets
    
    
    1Deferral of
      new regulatory assets
    
    
    (2
    )Income
      taxes
    
    
    (3
    )**Net
      increase in operating expenses and taxes**
    
    **$**
    **12**








Higher fuel costs in
the first three months of 2005, compared with the same period of 2004, resulted
principally from increased fossil and nuclear generation — up 28.1% and 29.8%,
respectively. Lower purchased power costs reflect lower KWH purchased, partially
offset by increased unit costs. Increased nuclear operating costs in the first
quarter of 2005 compared to the first quarter of 2004 were due to a refueling
outage (including an unplanned extension) at the Perry nuclear plant and a
mid-cycle inspection outage at the Davis-Besse nuclear plant in the first
quarter of 2005 and no scheduled outages in the first quarter of 2004. Other
operating costs decreased due in part to lower employee benefit
costs.





Depreciation charges
increased by $1 million in the first three months of 2005 compared to the same
period of 2004 due to an increase in depreciable property, partially offset by
the effect of revised service life assumptions for fossil generating plants.
Higher amortization of regulatory assets reflects the increased amortization of
transition costs. Increases in deferrals of new regulatory assets resulted from
higher shopping incentives ($0.5 million) and deferred interest on the shopping
incentives ($1.5 million).





*Other
Income*





Other income
decreased by $3 million in the first quarter of 2005, compared to the same
period of 2004, due to a decrease in interest income earned on nuclear
decommissioning trust investments and the accrual of a $1.6 million proposed NRC
fine related to the Davis-Besse Plant (see Outlook - Other Legal
Proceedings).





*Net Interest
Charges*





Net interest charges
continued to trend lower, decreasing by $1 million in the first three months of
2005 from the same period of 2004, reflecting redemptions and refinancing
subsequent to the end of the first quarter of 2004.





**Capital
Resources and Liquidity**





TE’s cash
requirements in 2005 for operating expenses, construction expenditures and
scheduled debt maturities are expected to be met without increasing its net debt and
preferred stock outstanding. Thereafter, TE expects to meet its contractual
obligations with a combination of cash from operations and funds from the
capital markets.





*Changes in Cash
Position*





There was no change
as of March 31, 2005 from December 31, 2004 in TE's cash and cash
equivalents of $15,000.





77





*Cash Flows From
Operating Activities*





Cash provided from
operating activities during the first quarter of 2005, compared with the first
quarter of 2004 were as follows:





**Three
      Months Ended**
      **March
      31,****Operating
      Cash Flows**
    
    **2005**
    
    **2004*****(in
      millions)***Cash earnings(1)
    
    $
    28
    
    $
    46Working
      capital and other
    
    
    26
    
    
    (9
    )Total Cash
      Flows from Operating Activities
    
    $
    54
    
    $
    37





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








Cash earnings (in
the table above) are not a measure of performance calculated in accordance with
GAAP. TE believes that cash
earnings is a useful financial measure because it provides investors and
management with an additional means of evaluating its cash-based operating
performance. The following table reconciles cash earnings with net
income.








**Three
      Months Ended**
      **March
      31,****Reconciliation
      of Cash Earnings**
    
    **2005**
    
    **2004*****(in
      millions)***Net Income
      (GAAP)
    
    $
    --
    
    $
    8Non-Cash
      Charges (Credits):Provision for
      depreciation
    
    
    15
    
    
    14Amortization
      of regulatory assets
    
    
    35
    
    
    34Nuclear fuel
      and capital lease amortization
    
    
    5
    
    
    6Deferral of
      new regulatory assets
    
    
    (9
    )
    
    (7
    )Deferred
      operating lease costs, net
    
    
    (15
    )
    
    (8
    )Accrued
      retirement benefits obligation
    
    
    1
    
    
    2Accrued
      compensation
    
    
    (2
    )
    
    (1
    )Deferred
      income taxes and investment tax credits, net
    
    
    (2
    )
    
    (2
    )Cash earnings
      (Non-GAAP)
    
    $
    28
    
    $
    46








Net cash provided
from operating activities increased by $17 million in the first quarter of 2005
from the first quarter of 2004 as a result of a $35 million increase in working
capital partially offset by a $18 million decrease in cash earnings described
above and under "Results of Operations". The change in working capital was
primarily due to changes in receivables and accounts payable.





*Cash Flows From
Financing Activities*





Net cash used for
financing activities decreased by $306,000 in the first quarter of 2005, as
compared to the same period of 2004, reflecting a change in net debt
redemptions.





TE had $137 million
of cash and temporary investments (which included short-term notes receivable
from associated companies) and $395 million of short-term indebtedness as of
March 31, 2005. TE has authorization from the PUCO to incur short-term debt
of up to $500 million (including the utility money pool described below). As of
March 31, 2005, TE had the capability to issue $907 million of additional
FMB on the basis of property additions and retired bonds under the terms of its
mortgage indenture. Based upon applicable earnings coverage tests, TE could
issue up to $475 million of preferred stock (assuming no additional debt was
issued as of March 31, 2005).





TE has the ability
to borrow from its regulated affiliates and FirstEnergy to meet its short-term
working capital requirements. FESC administers this money pool and tracks
surplus funds of FirstEnergy and its regulated subsidiaries. Companies receiving
a loan under the money pool agreements must repay the principal, together with
accrued interest, within 364 days of borrowing the funds. The rate of interest
is the same for each company receiving a loan from the pool and is based on the
average cost of funds available through the pool. The average interest rate for
borrowings in the first quarter of 2005 was 2.66%.





78




TE’s access to
capital markets and costs of financing are dependent on the ratings of its
securities and the securities of FirstEnergy. The ratings outlook on all
securities is stable.


On March 18,
2005, S&P stated that FirstEnergy’s Sammis NSR settlement was a very
favorable step for FirstEnergy, although it would not immediately affect
FirstEnergy’s ratings or outlook. S&P noted that it continues to monitor the
refueling outage at the Perry nuclear plant, which includes a detailed
inspection by the NRC, and that if FirstEnergy should exit the outage without
significant negative findings or delays the ratings outlook would be revised to
positive.





On April 20,
2005, Beaver County Industrial Development Authority pollution control bonds
aggregating $45 million were refunded. The new bonds were issued in a Dutch
Auction interest rate mode, insured with municipal bond insurance and secured by
FMB.





*Cash Flows From
Investing Activities*





Net cash used for
investing activities increased by $15 million in the first quarter of 2005 from
the same period of 2004. This increase was primarily due to increased property
additions and increased loans to associated companies, partially offset by the
reduction in lessor note investments.





TE’s capital
spending for the last three quarters of 2005 is expected to be about $46 million
(excluding $1 million for nuclear fuel). These cash requirements are expected to
be satisfied from internal cash and short-term borrowings.





TE’s capital
spending for the period 2005-2007 is expected to be about $192 million
(excluding nuclear fuel) of which approximately $56 million applies to 2005.
Investments for additional nuclear fuel during the 2005-2007 period are
estimated to total approximately $54 million, of which about $8 million applies
to 2005. During the same periods, TE’s nuclear fuel investments are expected to
be reduced by approximately $64 million and $20 million, respectively, as the
nuclear fuel is consumed.





**Off-Balance
Sheet Arrangements**





Obligations not
included on TE’s Consolidated Balance Sheet primarily consist of sale and
leaseback arrangements involving the Bruce Mansfield Plant and Beaver Valley
Unit 2. As of March  31, 2005, the present value of these operating lease
commitments, net of trust investments, totaled $566 million.





TE sells
substantially all of its retail customer receivables to CFC, a wholly owned
subsidiary of CEI. CFC subsequently transfers the receivables to a trust (a
“qualified special purpose entity” under SFAS 140) under an asset-backed
securitization agreement. This arrangement provided $48 million of off-balance
sheet financing as of March 31, 2005.





**Equity
Price Risk**





Included in TE’s
nuclear decommissioning trust investments are marketable equity securities
carried at their market value of approximately $194 million and $188 as of
March 31, 2005 and December 31, 2004, respectively. A hypothetical 10%
decrease in prices quoted by stock exchanges would result in a $19 million
reduction in fair value as of March 31, 2005. Changes in the fair value of
these investments are recorded on OCI unless recognized as a result of sales or
recognized as regulatory assets or liabilities.





**Outlook**





The electric industry continues to transition to a more competitive environment
and all of TE's customers can select alternative energy suppliers. TE continues
to deliver power to residential homes and businesses through its existing
distribution system, which remains regulated. Customer rates have been
restructured into separate components to support customer choice. TE has 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.





79





*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 TE's customers elects to obtain power from an alternative supplier, TE
reduces the customer's bill with a "generation shopping credit," based on the
generation component plus an incentive, and the customer receives a generation
charge from the alternative supplier. TE has continuing PLR responsibility to
its franchise customers through December 31, 2008.





As part of TE's
transition plan, it is obligated to supply electricity to customers who do not
choose an alternative supplier. TE is also required to provide 160 MW of low
cost supply to unaffiliated alternative suppliers who serve customers within its
service area. FES acts as an alternate supplier for a portion of the load in
TE's franchise area.





TE's revised Rate
Stabilization Plan extends current generation prices through 2008, ensuring
adequate generation supply at stabilized prices, and continues TE's support of
energy efficiency and economic development efforts. Other key components of the
revised Rate Stabilization Plan include the following:





·
    extension of
      the amortization period for transition costs being recovered through the
      RTC from mid-2007 to as late as mid-2008;





·
    deferral of
      interest costs on the accumulated customer shopping incentives as new
      regulatory assets; and





·
    ability to
      request increases in generation charges during 2006 through 2008, under
      certain limited conditions, for increases in fuel costs and
      taxes.





On December 9,
2004, the PUCO rejected the auction price results from a required competitive
bid process and issued an entry stating that the pricing under the approved
revised Rate Stabilization Plan will take effect on January 1, 2006. The
PUCO may require TE to undertake, no more often than annually, a similar
competitive bid process to secure generation for the years 2007 and 2008. Any
acceptance of future competitive bid results would terminate the Rate
Stabilization Plan pricing, but not the related approved accounting, and not
until twelve months after the PUCO authorizes such termination.





On December 30,
2004, TE filed an application with the PUCO seeking tariff adjustments to
recover increases of approximately $0.1 million in transmission and ancillary
service costs beginning January 1, 2006. TE 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.





TE records as
regulatory assets costs which have been authorized by the PUCO and the FERC for
recovery from customers in future periods and, without such authorization, would
have been charged to income when incurred. TE's regulatory assets as of
March 31, 2005 and December 2004 were $349 million and $375 million,
respectively. TE is deferring customer shopping incentives and interest costs as
new regulatory assets in accordance with its transition and rate stabilization
plans. These regulatory assets total $98 million as of March 31, 2005 and
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.





See Note 13 to the
consolidated financial statements for further details and a complete discussion
of regulatory matters in Ohio.





*Environmental
Matters*





TE accrues
environmental liabilities only when it concludes that it is probable that it has
an obligation for such costs and can reasonably determine the amount of such
costs. Unasserted claims are reflected in TE's determination of environmental
liabilities and are accrued in the period that they are both probable and
reasonably estimable.





80





*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 March 10, 2005, the EPA finalized the "Clean Air
Interstate Rule" covering a total of 28 states (including Ohio and Pennsylvania)
and the District of Columbia based on proposed findings that air emissions from
28 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. CAIR will require additional reductions of NOxand SO2emissions in two
phases (Phase I in 2009 for NOx, 2010 for
SO2and Phase II in
2015 for both NOxand SO2). TE's Ohio and
Pennsylvania fossil-fuel generation facilities will be subject to the caps on
SO2and NOxemissions.
According to the EPA, SO2emissions will be
reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule,
with reductions reaching 73% (from 2003 levels) by 2015, capping SO2emissions in
affected states to just 2.5 million tons annually. NOxemissions will be
reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule,
with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional
NOxcap of 1.3 million
tons annually. The future cost of compliance with these regulations may be
substantial and will depend on how they are ultimately implemented by the states
in which TE operates affected facilities.


*Mercury
Emissions*


In December 2000,
the EPA announced it would proceed with the development of regulations regarding
hazardous air pollutants from electric power plants, identifying mercury as the
hazardous air pollutant of greatest concern. On March 14, 2005, the EPA
finalized a cap-and-trade program to reduce mercury emissions in two phases from
coal-fired power plants. Initially, mercury emissions will decline by 2010 as a
"co-benefit" from implementation of SO 2 and NO x emission caps under
the EPA's CAIR program. Phase II of the mercury cap-and-trade program will cap
nationwide mercury emissions from coal-fired power plants at 15 tons per year by
2018. The future cost of compliance with these regulations may be
substantial.
 **
 *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 percent through
2012.


TE cannot currently
estimate the financial impact of climate change policies, although the potential
restrictions on CO 2 emissions could
require significant capital and other expenditures. However, the CO 2 emissions per KWH
of electricity generated by TE is lower than many regional competitors due to
TE's diversified generation sources which include low or non-CO 2 emitting gas-fired
and nuclear generators.





FirstEnergy plans to
issue a report that will disclose the Companies’ environmental activities,
including their plans to respond to environmental requirements. FirstEnergy
expects to complete the report by December 1, 2005 and will post the report
on its website, www.firstenergycorp.com .


**


*Regulation of Hazardous Waste*





TE has been named a
PRP at waste disposal sites, which may require cleanup under the Comprehensive
Environmental Response, Compensation and Liability Act of 1980. Allegations of
disposal of hazardous substances at historical sites and the liability involved
are often unsubstantiated and subject to dispute; however, federal law provides
that all PRPs for a particular site are liable on a joint and several basis.
Therefore, environmental liabilities that are considered probable have been
recognized on the Consolidated Balance Sheet as of March 31, 2005, based on
estimates of the total costs of cleanup, TE's proportionate responsibility for
such costs and the financial ability of other nonaffiliated entities to pay.
Included in Current Liabilities are accrued liabilities aggregating
approximately $0.2 million as of March 31, 2005. TE accrues environmental
liabilities only when it concludes that it is probable that it has an obligation
for such costs and can reasonably determine the amount of such costs. Unasserted
claims are reflected in TE's determination of environmental liabilities and are
accrued in the period that they are both probable and reasonably
estimable.





See Note 12(B) to
the consolidated financial statements for further details and a complete
discussion of environmental matters.





81





*Other Legal
Proceedings*





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





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. The U.S. - Canada Power System Outage Task Force’s
final report in April 2004 on the outages 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 contained 46
"recommendations to prevent or minimize the scope of future blackouts."
Forty-five of those recommendations related to broad industry or policy matters
while one, including subparts, related to activities the Task Force recommended
be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the
causes of the August 14, 2003 power outages. FirstEnergy implemented
several initiatives, both prior to and since the August 14, 2003 power
outages, which were independently verified by NERC as complete in 2004 and were
consistent with these and other recommendations and collectively enhance the
reliability of its electric system. 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 completed in 2004 had a material effect on its
continuing 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 March 31, 2005 for any expenditures in excess
of those actually incurred through that date.





Three substantially
similar actions were filed in various Ohio State courts by plaintiffs seeking to
represent customers who allegedly suffered damages as a result of the
August 14, 2003 power outages. All three cases were dismissed for lack of
jurisdiction. One case was refiled on January 12, 2004 at the PUCO. The other
two cases were appealed. One case was dismissed and no further appeal was
sought. In the remaining case, the Court of Appeals on March 31, 2005
affirmed the trial court’s decision dismissing the case. It is not yet known
whether further appeal will be sought. 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 was
filed on August 25, 2004 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.





FENOC received a
subpoena in late 2003 from a grand jury sitting in the United States District
Court for the Northern District of Ohio, Eastern Division requesting the
production of certain documents and records relating to the inspection and
maintenance of the reactor vessel head at the Davis-Besse Nuclear Power Station,
in which TE has a 48.62% interest. On December 10, 2004, FirstEnergy
received a letter from the United States Attorney's Office stating that FENOC is
a target of the federal grand jury investigation into alleged false statements
made to the NRC in the Fall of 2001 in response to NRC Bulletin 2001-01. The
letter also said that the designation of FENOC as a target indicates that, in
the view of the prosecutors assigned to the matter, it is likely that federal
charges will be returned against FENOC by the grand jury. On February 10,
2005, FENOC received an additional subpoena for documents related to root cause
reports regarding reactor head degradation and the assessment of reactor head
management issues at Davis-Besse.





82





On April 21,
2005, the NRC issued a NOV and proposed a $5.45 million civil penalty related to
the degradation of the Davis-Besse reactor vessel head described above. Under
the NRC’s letter, FENOC has ninety days to respond to this NOV. TE has
accrued the remaining liability for its share of the proposed fine of 
$1.6 million during the first quarter of 2005.





If it were ultimately determined that FirstEnergy or its subsidiaries has legal
liability based on the Davis-Besse head degradation, it could have a material
adverse effect on FirstEnergy's or any of its subsidiaries' financial condition
and results of operations.





On August 12,
2004, the NRC notified FENOC that it would 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 TE has a 19.91% interest. On April 4, 2005, the NRC held a public
forum to discuss FENOC’s performance at the Perry Nuclear Power Plant as
identified in the NRC's annual assessment letter to FENOC. Similar public
meetings are held with all nuclear power plant licensees following issuance by
the NRC of their annual assessments. According to the NRC, overall the Perry
Plant operated "in a manner that preserved public health and safety" and met all
cornerstone objectives although it remained under the heightened NRC oversight
since August 2004. During the public forum and in the annual assessment, the NRC
indicated that additional inspections will continue and that the plant must
improve performance to be removed from the Multiple/Repetitive Degraded
Cornerstone Column of the Action Matrix. If performance does not improve, the
NRC has a range of options under the Reactor Oversight Process from increased
oversight to possible impact to the plant’s 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 TE, and the Davis-Besse extended outage, have become the subject
of a formal order of investigation. The SEC's formal order of investigation also
encompasses issues raised during the SEC's examination of FirstEnergy and the
Companies under the PUHCA. Concurrent with this notification, FirstEnergy
received a subpoena asking for background documents and documents related to the
restatements and Davis-Besse issues. On December 30, 2004, FirstEnergy
received a second subpoena asking for documents relating to issues raised during
the SEC's PUHCA examination. FirstEnergy has cooperated fully with the informal
inquiry and will continue to do so with the formal investigation.





If it were
ultimately determined that FirstEnergy or its subsidiaries have legal liability
or are otherwise made subject to liability based on the above matters, it could
have a material adverse effect on FirstEnergy's or its subsidiaries' financial
condition and results of operations.





See Note 12(C) to
the consolidated financial statements for further details and a complete
discussion of other legal proceedings.





**New
Accounting Standards and Interpretations**





*FIN 47, “Accounting for Conditional Asset Retirement
Obligations - an interpretation of FASB Statement No. 143”*





On March 30,
2005, the FASB issued this interpretation to clarify the scope and timing of
liability recognition for conditional asset retirement obligations. Under this
interpretation, companies are required to recognize a liability for the fair
value of an asset retirement obligation that is conditional on a future event,
if the fair value of the liability can be reasonably estimated. In instances
where there is insufficient information to estimate the liability, the
obligation is to be recognized in the first period in which sufficient
information becomes available to estimate its fair value. If the fair value
cannot be reasonably estimated, that fact and the reasons why must be disclosed.
This interpretation is effective no later than the end of fiscal years ending
after December 15, 2005. FirstEnergy is currently evaluating the effect
this standard will have 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, FirstEnergy will continue
to evaluate its investments as required by existing authoritative
guidance.








83





**PENNSYLVANIA
      POWER COMPANY****CONSOLIDATED
      STATEMENTS OF INCOME AND COMPREHENSIVE
      INCOME****(Unaudited)******
    
    **Three
      Months Ended****March
      31,****2005**
    
    **2004****STATEMENTS
      OF INCOME**
    
    
    
    ***(In
      thousands)*****OPERATING
      REVENUES**
    
    
    
    
    $
    134,484
    
    $
    142,623**OPERATING
      EXPENSES AND TAXES:**Fuel
    
    
    
    
    
    5,620
    
    
    6,206Purchased
      power
    
    
    
    
    
    46,980
    
    
    48,508Nuclear
      operating costs
    
    
    
    
    
    19,948
    
    
    18,623Other
      operating costs
    
    
    
    
    
    12,768
    
    
    13,685Provision for
      depreciation
    
    
    
    
    
    3,694
    
    
    3,362Amortization
      of regulatory assets
    
    
    
    
    
    9,882
    
    
    10,076General
      taxes
    
    
    
    
    
    6,472
    
    
    6,634Income
      taxes
    
    
    
    
    
    12,421
    
    
    15,038Total
      operating expenses and taxes
    
    
    
    
    
    117,785
    
    
    122,132**OPERATING
      INCOME**
    
    
    
    
    
    16,699
    
    
    20,491**OTHER
      INCOME (EXPENSE) (net of income taxes)**
    
    
    
    
    
    (745
    )
    
    982**NET
      INTEREST CHARGES:**Interest
      expense
    
    
    
    
    
    2,319
    
    
    2,725Allowance for
      borrowed funds used during construction
    
    
    
    
    
    (1,367
    )
    
    (922
    )Net interest
      charges
    
    
    
    
    
    952
    
    
    1,803**NET
      INCOME**
    
    
    
    
    
    15,002
    
    
    19,670**PREFERRED
      STOCK DIVIDEND REQUIREMENTS**
    
    
    
    
    
    640
    
    
    640**EARNINGS
      ON COMMON STOCK**
    
    
    
    
    $
    14,362
    
    $
    19,030**STATEMENTS
      OF COMPREHENSIVE INCOME****NET
      INCOME**
    
    
    
    
    $
    15,002
    
    $
    19,670**OTHER
      COMPREHENSIVE INCOME**
    
    
    
    
    
    --
    
    
    --**TOTAL
      COMPREHENSIVE INCOME**
    
    
    
    
    $
    15,002
    
    $
    19,670The preceding
      Notes to Consolidated Financial Statements as they relate to Pennsylvania
      Power Company are an integral part of these
      statements.
   84
  **PENNSYLVANIA
      POWER COMPANY****CONSOLIDATED
      BALANCE SHEETS****(Unaudited)****March
      31,**
    
    **December
      31,****2005**
    
    **2004*****(In
      thousands)*****ASSETS****UTILITY
      PLANT:**In
      service
    
    
    
    
    $
    873,780
    
    $
    866,303Less -
      Accumulated provision for depreciation
    
    
    
    
    
    364,354
    
    
    356,020509,426
    
    
    510,283Construction
      work in progress-Electric
      plant
    
    
    
    
    
    121,145
    
    
    104,366Nuclear
      fuel
    
    
    
    
    
    7,647
    
    
    3,362128,792
    
    
    107,728638,218
    
    
    618,011**OTHER
      PROPERTY AND INVESTMENTS:**Nuclear plant
      decommissioning trusts
    
    
    
    
    
    142,317
    
    
    143,062Long-term
      notes receivable from associated companies
    
    
    
    
    
    32,890
    
    
    32,985Other
    
    
    
    
    
    530
    
    
    722175,737
    
    
    176,769**CURRENT
      ASSETS:**Cash and cash
      equivalents
    
    
    
    
    
    38
    
    
    38Notes
      receivable from associated companies
    
    
    
    
    
    545
    
    
    431Receivables-Customers
      (less accumulated provisions of $940,000 and $888,000,respectively,
      for uncollectible accounts)
    
    
    
    
    
    42,984
    
    
    44,282Associated
      companies
    
    
    
    
    
    13,019
    
    
    23,016Other
    
    
    
    
    
    1,059
    
    
    1,656Materials and
      supplies, at average cost
    
    
    
    
    
    37,705
    
    
    37,923Prepayments
      and other
    
    
    
    
    
    22,405
    
    
    8,924117,755
    
    
    116,270**DEFERRED
      CHARGES**
    
    
    
    
    
    9,921
    
    
    10,106$
    941,631
    
    $
    921,156**CAPITALIZATION
      AND LIABILITIES****CAPITALIZATION:**Common
      stockholder's equity-Common stock,
      $30 par value, authorized 6,500,000 shares -6,290,000
      shares outstanding
    
    
    
    
    $
    188,700
    
    $
    188,700Other paid-in
      capital
    
    
    
    
    
    64,690
    
    
    64,690Accumulated
      other comprehensive loss
    
    
    
    
    
    (13,706
    )
    
    (13,706
    )Retained
      earnings
    
    
    
    
    
    94,057
    
    
    87,695Total common
      stockholder's equity
    
    
    
    
    
    333,741
    
    
    327,379Preferred
      stock
    
    
    
    
    
    39,105
    
    
    39,105Long-term debt
      and other long-term obligations
    
    
    
    
    
    121,889
    
    
    133,887494,735
    
    
    500,371**CURRENT
      LIABILITIES:**Currently
      payable long-term debt
    
    
    
    
    
    38,524
    
    
    26,524Accounts
      payable-Associated
      companies
    
    
    
    
    
    43,569
    
    
    46,368Other
    
    
    
    
    
    1,345
    
    
    1,436Notes payable
      to associated companies
    
    
    
    
    
    10,644
    
    
    11,852Accrued
      taxes
    
    
    
    
    
    25,475
    
    
    14,055Accrued
      interest
    
    
    
    
    
    1,614
    
    
    1,872Other
    
    
    
    
    
    9,156
    
    
    8,802130,327
    
    
    110,909**NONCURRENT
      LIABILITIES:**Accumulated
      deferred income taxes
    
    
    
    
    
    89,060
    
    
    93,418Accumulated
      deferred investment tax credits
    
    
    
    
    
    3,150
    
    
    3,222Asset
      retirement obligation
    
    
    
    
    
    140,560
    
    
    138,284Retirement
      benefits
    
    
    
    
    
    50,116
    
    
    49,834Regulatory
      liabilities
    
    
    
    
    
    26,523
    
    
    18,454Other
    
    
    
    
    
    7,160
    
    
    6,664316,569
    
    
    309,876**COMMITMENTS
      AND CONTINGENCIES (Note 12)**$
    941,631
    
    $
    921,156The preceding
      Notes to Consolidated Financial Statements as they relate to Pennsylvania
      Power Company are an integral part of these balance sheets.
   85
   **PENNSYLVANIA
      POWER COMPANY****CONSOLIDATED
      STATEMENTS OF CASH FLOWS****(Unaudited)******
    
    **Three
      Months Ended****March
      31,****2005**
    
    **2004*****(In
      thousands)*****CASH
      FLOWS FROM OPERATING ACTIVITIES:**Net
      income
    
    
    
    
    $
    15,002
    
    $
    19,670Adjustments to
      reconcile net income to net cash from operating
activities-Provision for
      depreciation
    
    
    
    
    
    3,694
    
    
    3,362Amortization
      of regulatory assets
    
    
    
    
    
    9,882
    
    
    10,076Nuclear fuel
      and other amortization
    
    
    
    
    
    4,140
    
    
    4,565Deferred
      income taxes and investment tax credits, net
    
    
    
    
    
    (2,311
    )
    
    (1,806
    )Decrease
      (Increase) in operating assets-Receivables
    
    
    
    
    
    11,892
    
    
    (214
    )Materials and
      supplies
    
    
    
    
    
    218
    
    
    (1,075
    )Prepayments
      and other current assets
    
    
    
    
    
    (13,481
    )
    
    (13,333
    )Increase
      (Decrease) in operating liabilities-Accounts
      payable
    
    
    
    
    
    (2,890
    )
    
    3,740Accrued
      taxes
    
    
    
    
    
    11,420
    
    
    8,809Accrued
      interest
    
    
    
    
    
    (258
    )
    
    (1,956
    )Other
    
    
    
    
    
    778
    
    
    2,857Net cash
      provided from operating activities
    
    
    
    
    
    38,086
    
    
    34,695**CASH
      FLOWS FROM FINANCING ACTIVITIES:**New
      Financing-Short-term
      borrowings, net
    
    
    
    
    
    --
    
    
    29,084Redemptions
      and Repayments-Long-term
      debt
    
    
    
    
    
    --
    
    
    (42,302
    )Short-term
      borrowings, net
    
    
    
    
    
    (1,208
    )
    
    --Dividend
      Payments-Common
      stock
    
    
    
    
    
    (8,000
    )
    
    (8,000
    )Preferred
      stock
    
    
    
    
    
    (640
    )
    
    (640
    )Net cash used
      for financing activities
    
    
    
    
    
    (9,848
    )
    
    (21,858
    )**CASH
      FLOWS FROM INVESTING ACTIVITIES:**Property
      additions
    
    
    
    
    
    (28,522
    )
    
    (13,998
    )Contributions
      to nuclear decommissioning trusts
    
    
    
    
    
    (399
    )
    
    (399
    )Loans to
      associated companies
    
    
    
    
    
    (19
    )
    
    (116
    )Other
    
    
    
    
    
    702
    
    
    1,676Net cash used
      for investing activities
    
    
    
    
    
    (28,238
    )
    
    (12,837
    )Net change in
      cash and cash equivalents
    
    
    
    
    
    --
    
    
    --Cash and cash
      equivalents at beginning of period
    
    
    
    
    
    38
    
    
    40Cash and cash
      equivalents at end of period
    
    
    
    
    $
    38
    
    $
    40The preceding
      Notes to Consolidated Financial Statements as they relate to Pennsylvania
      Power Company are an integral part of these
      statements.
   86


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





























To the Stockholders
and Board of


Directors of
Pennsylvania Power Company:





We have reviewed the
accompanying consolidated balance sheet of Pennsylvania Power Company and its
subsidiary as of March 31, 2005, and the related consolidated statements of
income, comprehensive income and cash flows for each of the three-month periods
ended March 31, 2005 and 2004. These interim financial statements are the
responsibility of the Company’s management.





We conducted our
review in accordance with the standards of the Public Company Accounting
Oversight Board (United States). A review of interim financial information
consists principally of applying analytical procedures and making inquiries of
persons responsible for financial and accounting matters. It is substantially
less in scope than an audit conducted in accordance with the standards of the
Public Company Accounting Oversight Board, the objective of which is the
expression of an opinion regarding the financial statements taken as a whole.
Accordingly, we do not express such an opinion.





Based on our review,
we are not aware of any material modifications that should be made to the
accompanying consolidated interim financial statements for them to be in
conformity with accounting principles generally accepted in the United States of
America.





We previously
audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheet as of
December 31, 2004, and the related consolidated statements of income,
capitalization, common stockholder’s equity, preferred stock, cash flows and
taxes for the year then ended, management’s assessment of the effectiveness of
the Company’s internal control over financial reporting as of December 31,
2004 and the effectiveness of the Company’s internal control over financial
reporting as of December 31, 2004; and in our report (which contained
references to the Company’s change in its method of accounting for asset
retirement obligations as of January 1, 2003 as discussed in Note 2(G) to
those consolidated financial statements) dated March 7, 2005, we expressed
unqualified opinions thereon. The consolidated financial statements and
management’s assessment of the effectiveness of internal control over financial
reporting referred to above are not presented herein. In our opinion, the
information set forth in the accompanying consolidated balance sheet information
as of December 31, 2004, is fairly stated in all material respects in
relation to the consolidated balance sheet from which it has been
derived.














PricewaterhouseCoopers
LLP


Cleveland,
Ohio


May 3,
2005








87





**PENNSYLVANIA
POWER COMPANY**





**MANAGEMENT’S
DISCUSSION AND ANALYSIS OF**


**RESULTS OF
OPERATIONS AND FINANCIAL CONDITION**








Penn is a wholly
owned, electric utility subsidiary of OE. Penn conducts business in western
Pennsylvania, providing regulated electric distribution services. Penn also
provides generation services to those customers electing to retain Penn as their
power supplier. Penn provides power directly to wholesale customers under
previously negotiated contracts. Penn has unbundled the price of electricity
into its component elements - including generation, transmission, distribution
and transition charges. Its power supply requirements are provided by FES - an
affiliated company.





**Results
of Operations**





Earnings on common
stock in the first quarter of 2005 decreased to $14 million from $19 million in
the first quarter of 2004. The lower earnings resulted from decreased operating
revenues, partially offset by lower operating expenses and taxes and lower net
interest charges.





Operating revenues
decreased by $8 million, or 6%, in the first quarter of 2005 as compared with
the first quarter of 2004. The lower revenues primarily resulted from a $9
million decrease in wholesale sales to FES due to less nuclear generation
available for sale. Higher retail generation sales revenues of $3 million
resulted from higher commercial and industrial sales of $1 million and $2
million, respectively, as a result of higher composite unit prices and increased
KWH sales. The increased sales reflected an improving service area economy
including higher sales to the steel industry. These increases were partially
offset by a $0.2 million residential revenues decrease reflecting lower sales
volume (0.8%) and unit prices.





A $2 million
reduction in distribution throughput revenues was primarily due to lower unit
prices, partially offset by higher KWH deliveries to commercial and industrial
customers. The lower unit prices are attributable to changes in Penn's CTC rate
schedules in April 2004 as a result of the annual CTC
reconciliation.





Changes in electric
generation and distribution deliveries in the first quarter of 2005 from the
same quarter in 2004 are summarized in the following table:





**Changes
      in KWH Sales*****Increase
      (Decrease)***Electric
      Generation:Retail
    
    
    0.7
    %Wholesale
    
    
    (7.9
    )%Total Electric
      Generation Sales
    
    
    (4.3
    )%Distribution
      Deliveries:Residential
    
    
    (0.8
    )%Commercial
    
    
    2.1
    %Industrial
    
    
    1.3
    %Total
      Distribution Deliveries
    
    
    0.7
    %








*Operating
Expenses and Taxes*





Total operating
expenses and taxes decreased by $4 million in the first quarter of 2005 from the
first quarter of 2004. Lower fuel costs in
the first quarter of 2005, compared with the same quarter of 2004, resulted from
reduced nuclear generation. Lower purchased power costs in the first three
months of 2005 reflected decreased KWH purchases and higher unit costs. Nuclear
operating costs increased due to the Perry scheduled refueling outage (including
an unplanned extension) in the first quarter of 2005 and the absence of nuclear
refueling outages in the same period last year. Other operating expenses
decreased primarily because of lower employee benefit costs.





*Other Income
(Expense)*





Other income
decreased $2 million in the first quarter of 2005, compared with the first
quarter of 2004, due to the first quarter 2005 accruals for a potential $0.7
million civil penalty and $0.8 million for potential contributions toward
environmentally beneficial projects related to the Sammis Plant settlement (see
Outlook - Environmental Matters) and the absence of a 2004 $1 million gain from
the sale of an investment.





88





*Net Interest
Charges*





Net interest charges
continued to trend lower, decreasing by $851,000 in the first quarter of 2005
from the same period last year, reflecting redemptions of $22 million total
principal amount of debt securities since the first quarter of
2004.





**Capital
Resources and Liquidity**





Penn’s cash
requirements in 2005 and thereafter for
operating expenses, construction expenditures, scheduled debt maturities and
preferred stock redemptions are expected to be met with a combination
of cash from operations and funds from the capital markets. Available borrowing
capacity under credit facilities will be used to manage working capital
requirements.





***Changes
in Cash Position***





Penn had $38,000 of
cash and cash equivalents as of March 31, 2005 and December 31,
2004.





***Cash
Flows From Operating Activities***





Net cash provided
from operating activities in the first quarter of 2005, compared with the
corresponding 2004 period, was as follows:





**Three
      Months Ended****March
      31,****Operating
      Cash Flows**
    
    **2005**
    
    **2004*****(In
      millions)***Cash
      earnings(1)
    
    $
    30
    
    $
    38Working
      capital and other
    
    
    8
    
    
    (3
    )Total Cash
      Flows from Operating Activities
    
    $
    38
    
    $
    35





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





Cash earnings (in
the table above) are not a measure of performance calculated in accordance with
GAAP. Penn believes that cash earnings is a useful financial measure because it
provides investors and management with an additional means of evaluating its
cash-based operating performance. The following table reconciles cash earnings
with net income.





**Three
      Months Ended****March
      31,****Reconciliation
      of Cash Earnings**
    
    **2005**
    
    **2004*****(In
      millions)***Net Income
      (GAAP)
    
    $
    15
    
    $
    20Non-Cash
      Charges (Credits):Provision for
      depreciation
    
    
    3
    
    
    3Amortization
      of regulatory assets
    
    
    10
    
    
    10Nuclear fuel
      and other amortization
    
    
    4
    
    
    5Deferred
      income taxes and investment tax credits, net
    
    
    (2
    )
    
    (2
    )Other non-cash
      expenses
    
    
    --
    
    
    2Cash earnings
      (Non-GAAP)
    
    $
    30
    
    $
    38




The $8 million
decrease in cash earnings is described under “Results of Operations”. The $11 million working capital change was
primarily due to changes of $12 million in receivables and $3 million in accrued
taxes, partially offset by a $7 million change in accounts payable.





89





***Cash
Flows From Financing Activities***





Net cash used for
financing activities totaled $10 million in the first quarter of 2005, compared
with $22 million in the first quarter of 2004. This decrease resulted from
reduced debt redemptions in the first quarter of 2005, compared with the
corresponding 2004 period.





Penn had $583,000 of
cash and temporary investments (which included short-term notes receivable from
associated companies) and $11 million of short-term indebtedness with associated
companies as of March 31, 2005. Penn has authorization from the SEC to
incur short-term debt up to its charter limit of $49 million (including the
utility money pool). Penn had the capability to issue $532 million of additional
FMB on the basis of property additions and retired bonds as of March 31,
2005. Based upon applicable earnings coverage tests, Penn could issue up to $367
million of preferred stock (assuming no additional debt was issued) as of
March 31, 2005.





Penn has the ability
to borrow from its regulated affiliates and FirstEnergy to meet its short-term
working capital requirements. FESC administers this money pool and tracks
surplus funds of FirstEnergy and its regulated subsidiaries, as well as proceeds
available from bank borrowings. Available bank borrowings include $1.75 billion
from FirstEnergy’s and OE’s revolving credit facilities. Companies receiving a
loan under the money pool agreements must repay the principal amount of such a
loan, together with accrued interest, within 364 days of borrowing the funds.
The rate of interest is the same for each company receiving a loan from the pool
and is based on the average cost of funds available through the pool. The
average interest rate for borrowings under these arrangements in the first
quarter of 2005 was 2.66%.





In addition, Penn
has a $25 million receivables financing facility through its subsidiary. As of
March 31, 2005, the facility was undrawn; it expires June 30, 2005 and
is expected to be renewed.





On May 16,
2005, Penn intends to redeem all 127,500 outstanding shares of 7.625% preferred
stock at $102.29 per share and all 250,000 outstanding shares of 7.75% preferred
stock at $100 per share, both plus accrued dividends to the date of redemption.





Penn’s access to
capital markets and costs of financing are dependent on the ratings of its
securities and the securities of OE and FirstEnergy. The ratings outlook on all
securities is stable.





On March 18,
2005, S&P stated that FirstEnergy’s Sammis NSR settlement was a very
favorable step for FirstEnergy, although it would not immediately affect
FirstEnergy’s ratings or outlook. S&P noted that it continues to monitor the
refueling outage at the Perry nuclear plant, which includes a detailed
inspection by the NRC, and that if FirstEnergy should exit the outage without
significant negative findings or delays the ratings outlook would be revised to
positive.





***Cash
Flows From Investing Activities***





Net cash used in
investing activities totaled $28 million in the first quarter of 2005, compared
with $13 million in the same quarter of 2004. The $15 million increase in the
2005 period reflects an increase in property additions.





During the remaining
three quarters of 2005, capital requirements for property additions are expected
to be about $67 million, including $9 million for nuclear fuel. Penn has
additional requirements of approximately $2 million to meet sinking fund
requirements for preferred stock and maturing long-term debt during the
remainder of 2005. These cash requirements are expected to be satisfied from
internal cash and short-term credit arrangements.





Penn’s capital
spending for the period 2005-2007 is expected to be about $227 million
(excluding nuclear fuel) of which approximately $82 million applies to 2005.
Investments for additional nuclear fuel during the 2005-2007 period are
estimated to be approximately $64 million, of which about $13 million relates to
2005. During the same periods, Penn’s nuclear fuel investments are expected to
be reduced by approximately $52 million and $17 million, respectively, as the
nuclear fuel is consumed. Penn had no other material obligations as of
March 31, 2005 that have not been recognized on its Consolidated Balance
Sheet.





**Equity
Price Risk**


Included in Penn’s
nuclear decommissioning trust investments are marketable equity securities
carried at their market value of approximately $56 million and $57 million as of
March 31, 2005 and December 31, 2004, respectively. A hypothetical 10%
decrease in prices quoted by stock exchanges would result in a $6 million
reduction in fair value as of March 31, 2005.





90





**Outlook**





The electric
industry continues to transition to a more competitive environment and all of
Penn's customers can select alternative energy suppliers. Penn continues to
deliver power to residential homes and businesses through its existing
distribution system, which remains regulated. Customer rates have been
restructured into separate components to support customer choice. Penn has 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***




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





Regulatory assets
and liabilities are costs which have been authorized by the PPUC and the FERC
for recovery from or credit to customers in future periods and, without such
authorization, would have been charged or credited to income when incurred.
Penn's net regulatory liabilities were approximately $27 million and $18 million
as of March 31, 2005 and December 31, 2004, respectively, and are
included in Noncurrent Liabilities on the Consolidated Balance
Sheets.





See Note 13 to the
consolidated financial statements for further details and a complete discussion
of regulatory matters in Pennsylvania, including a more detailed discussion of
reliability initiatives.





***Environmental
Matters***





Penn accrues
environmental liabilities only when it concludes that it is probable that it has
an obligation for such costs and can reasonably determine the amount of such
costs. Unasserted claims are reflected in Penn’s determination of environmental
liabilities and are accrued in the period that they are both probable and
reasonably estimable.





*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 March 10, 2005, the EPA finalized the "Clean Air
Interstate Rule" covering a total of 28 states (including Ohio and Pennsylvania)
and the District of Columbia based on proposed findings that air emissions from
28 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. CAIR will require additional reductions of NO x and SO 2 emissions in two
phases (Phase I in 2009 for NO x , 2010 for
SO 2 and Phase II in
2015 for both NO x and SO 2 ). Penn's Ohio and
Pennsylvania fossil-fuel generation facilities will be subject to the caps on
SO 2 and NO x emissions. According
to the EPA, SO 2 emissions will be
reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule,
with reductions reaching 73% (from 2003 levels) by 2015, capping SO 2 emissions in
affected states to just 2.5 million tons annually. NO x emissions will be
reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule,
with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional
NO x cap of 1.3 million
tons annually. The future cost of compliance with these regulations may be
substantial and will depend on how they are ultimately implemented by the states
in which Penn operates affected facilities.


*Mercury
Emissions*




In December 2000,
the EPA announced it would proceed with the development of regulations regarding
hazardous air pollutants from electric power plants, identifying mercury as the
hazardous air pollutant of greatest concern. On March 14, 2005, the EPA
finalized a cap-and-trade program to reduce mercury emissions in two phases from
coal-fired power plants. Initially, mercury emissions will decline by 2010 as a
"co-benefit" from implementation of SO 2 and NO x emission caps under
the EPA's CAIR program. Phase II of the mercury cap-and-trade program will cap
nationwide mercury emissions from coal-fired power plants at 15 tons per year by
2018. The future cost of compliance with these regulations may be
substantial.





91





*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 (DOJ) 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. On March 18, 2005, OE and
Penn announced that they had reached a settlement with the EPA, the DOJ and
three states (Connecticut, New Jersey, and New York) that resolved all issues
related to the W. H. Sammis Plant New Source Review litigation. This settlement
agreement, which is in the form of a Consent Decree subject to a thirty-day
public comment period that ended on April 29, 2005 and final approval by the
District Court Judge, requires OE and Penn to reduce emissions from the W. H.
Sammis Plant and other plants through the installation of pollution control
devices requiring capital expenditures currently estimated to be $1.1 billion
(primarily in the 2008 to 2011 time period). The settlement agreement also
requires OE and Penn to spend up to $25 million towards environmentally
beneficial projects, which include wind energy purchase power agreements over a
20-year term. OE and Penn also agreed to pay a civil penalty of $8.5 million
(Penn's share is $0.7 million). Results for the first quarter of 2005 include
the $0.7 million penalty payable by Penn and a $0.8 million liability for cash
contributions toward environmentally beneficial projects.





*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 percent through
2012.


Penn cannot
currently estimate the financial impact of climate change policies, although the
potential restrictions on CO 2 emissions could
require significant capital and other expenditures. However, the CO 2 emissions per KWH
of electricity generated by Penn is lower than many regional competitors due to
Penn's diversified generation sources which include low or non-CO 2 emitting gas-fired
and nuclear generators.





FirstEnergy plans to
issue a report that will disclose the Companies’ environmental activities,
including their plans to respond to environmental requirements. FirstEnergy
expects to complete the report by December 1, 2005 and will post the report
on its web site, www.firstenergycorp.com .





***Other
Legal Proceedings***





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





92




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. The U.S. - Canada Power System Outage Task Force’s
final report in April 2004 on the outages 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 contained 46
"recommendations to prevent or minimize the scope of future blackouts."
Forty-five of those recommendations related to broad industry or policy matters
while one, including subparts, related to activities the Task Force recommended
be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the
causes of the August 14, 2003 power outages. FirstEnergy implemented
several initiatives, both prior to and since the August 14, 2003 power
outages, which were independently verified by NERC as complete in 2004 and were
consistent with these and other recommendations and collectively enhance the
reliability of its electric system. 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 completed in 2004 had a material effect on its
continuing 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 March 31, 2005 for any expenditures in excess
of those actually incurred through that date.





One complaint was
filed on August 25, 2004 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.





On August 12,
2004, the NRC notified FENOC that it would 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 Penn has a 5.24% interest. On April 4, 2005, the NRC held a public
forum to discuss FENOC’s performance at the Perry Nuclear Power Plant as
identified in the NRC's annual assessment letter to FENOC.  Similar public
meetings are held with all nuclear power plant licensees following issuance by
the NRC of their annual assessments. According to the NRC, overall the Perry
Plant operated "in a manner that preserved public health and safety" and met all
cornerstone objectives although it remained under the heightened NRC oversight
since August 2004. During the public forum and in the annual assessment, the NRC
indicated that additional inspections will continue and that the plant must
improve performance to be removed from the Multiple/Repetitive Degraded
Cornerstone Column of the Action Matrix. If performance does not improve, the
NRC has a range of options under the Reactor Oversight Process from increased
oversight to possible impact to the plant’s operating authority. As a result,
these matters could have a material adverse effect on FirstEnergy's or its
subsidiaries' financial condition.





See Note 12(C) to
the consolidated financial statements for further details and a complete
discussion of other legal proceedings.





93





**New
Accounting Standards and Interpretations**





*FIN 47, “Accounting for Conditional Asset Retirement
Obligations - an interpretation of FASB Statement No. 143”*





On March 30,
2005, the FASB issued this interpretation to clarify the scope and timing of
liability recognition for conditional asset retirement obligations. Under this
interpretation, companies are required to recognize a liability for the fair
value of an asset retirement obligation that is conditional on a future event,
if the fair value of the liability can be reasonably estimated. In instances
where there is insufficient information to estimate the liability, the
obligation is to be recognized in the first period in which sufficient
information becomes available to estimate its fair value. If the fair value
cannot be reasonably estimated, that fact and the reasons why must be disclosed.
This interpretation is effective no later than the end of fiscal years ending
after December 15, 2005. FirstEnergy is currently evaluating the effect
this standard will have 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, FirstEnergy will continue
to evaluate its investments as required by existing authoritative
guidance.








94





**JERSEY
      CENTRAL POWER & LIGHT COMPANY****CONSOLIDATED
      STATEMENTS OF INCOME AND COMPREHENSIVE
      INCOME****(Unaudited)******
    
    **Three
      Months Ended****March
      31,****2005**
    
    **2004****STATEMENTS
      OF INCOME**
    
    
    
    ***(In
      thousands)*****OPERATING
      REVENUES**
    
    
    
    
    $
    529,092
    
    $
    498,124**OPERATING
      EXPENSES AND TAXES:**Purchased
      power
    
    
    
    
    
    277,132
    
    
    270,733Other
      operating costs
    
    
    
    
    
    101,067
    
    
    86,816Provision for
      depreciation
    
    
    
    
    
    20,206
    
    
    19,075Amortization
      of regulatory assets
    
    
    
    
    
    68,374
    
    
    64,485General
      taxes
    
    
    
    
    
    15,440
    
    
    15,932Income
      taxes
    
    
    
    
    
    12,483
    
    
    9,113Total
      operating expenses and taxes
    
    
    
    
    
    494,702
    
    
    466,154**OPERATING
      INCOME**
    
    
    
    
    
    34,390
    
    
    31,970**OTHER
      INCOME (net of income taxes)**
    
    
    
    
    
    44
    
    
    1,503**NET
      INTEREST CHARGES:**Interest on
      long-term debt
    
    
    
    
    
    19,405
    
    
    20,728Allowance for
      borrowed funds used during construction
    
    
    
    
    
    (403
    )
    
    (120
    )Deferred
      interest
    
    
    
    
    
    (911
    )
    
    (923
    )Other interest
      expense
    
    
    
    
    
    1,824
    
    
    390Net interest
      charges
    
    
    
    
    
    19,915
    
    
    20,075**NET
      INCOME**
    
    
    
    
    
    14,519
    
    
    13,398**PREFERRED
      STOCK DIVIDEND REQUIREMENTS**
    
    
    
    
    
    125
    
    
    125**EARNINGS
      ON COMMON STOCK**
    
    
    
    
    $
    14,394
    
    $
    13,273**STATEMENTS
      OF COMPREHENSIVE INCOME****NET
      INCOME**
    
    
    
    
    $
    14,519
    
    $
    13,398**OTHER
      COMPREHENSIVE INCOME (LOSS):**Unrealized
      gain (loss) on derivative hedges
    
    
    
    
    
    69
    
    
    (14
    )Unrealized
      loss on available for sale securities
    
    
    
    
    
    --
    
    
    (8
    )Other
      comprehensive income (loss)
    
    
    
    
    
    69
    
    
    (22
    )Income tax
      related to other comprehensive income
    
    
    
    
    
    (28
    )
    
    3Other
      comprehensive income (loss), net of tax
    
    
    
    
    
    41
    
    
    (19
    )**TOTAL
      COMPREHENSIVE INCOME**
    
    
    
    
    $
    14,560
    
    $
    13,379The preceding
      Notes to Consolidated Financial Statements as they relate to Jersey
      Central Power & Light Company are an integral partof these
      statements.
     95
  **JERSEY
      CENTRAL POWER & LIGHT COMPANY****CONSOLIDATED
      BALANCE SHEETS****(Unaudited)****March
      31,**
    
    **December
      31,****2005**
    
    **2004*****(In
      thousands)*****ASSETS****UTILITY
      PLANT:**In
      service
    
    
    
    
    $
    3,755,666
    
    $
    3,730,767Less -
      Accumulated provision for depreciation
    
    
    
    
    
    1,395,942
    
    
    1,380,7752,359,724
    
    
    2,349,992Construction
      work in progress
    
    
    
    
    
    76,054
    
    
    75,0122,435,778
    
    
    2,425,004**OTHER
      PROPERTY AND INVESTMENTS:**Nuclear plant
      decommissioning trusts
    
    
    
    
    
    137,142
    
    
    138,205Nuclear fuel
      disposal trust
    
    
    
    
    
    160,757
    
    
    159,696Long-term
      notes receivable from associated companies
    
    
    
    
    
    21,335
    
    
    20,436Other
    
    
    
    
    
    16,362
    
    
    19,379335,596
    
    
    337,716**CURRENT
      ASSETS:**Cash and cash
      equivalents
    
    
    
    
    
    41
    
    
    162Receivables-Customers
      (less accumulated provisions of $3,090,000 and $3,881,000,respectively,
      for uncollectible accounts)
    
    
    
    
    
    201,196
    
    
    201,415Associated
      companies
    
    
    
    
    
    34,961
    
    
    86,531Other (less
      accumulated provisions of $263,000 and $162,000,respectively,
      for uncollectible accounts)
    
    
    
    
    
    76,837
    
    
    39,898Materials and
      supplies, at average cost
    
    
    
    
    
    2,352
    
    
    2,435Prepayments
      and other
    
    
    
    
    
    22,239
    
    
    31,489337,626
    
    
    361,930**DEFERRED
      CHARGES:**Regulatory
      assets
    
    
    
    
    
    2,267,795
    
    
    2,176,520Goodwill
    
    
    
    
    
    1,983,740
    
    
    1,985,036Other
    
    
    
    
    
    4,568
    
    
    4,9784,256,103
    
    
    4,166,534$
    7,365,103
    
    $
    7,291,184**CAPITALIZATION
      AND LIABILITIES****CAPITALIZATION:**Common
      stockholder's equity-Common stock,
      $10 par value, authorized 16,000,000 shares -15,371,270
      shares outstanding
    
    
    
    
    $
    153,713
    
    $
    153,713Other paid-in
      capital
    
    
    
    
    
    3,013,912
    
    
    3,013,912Accumulated
      other comprehensive loss
    
    
    
    
    
    (55,493
    )
    
    (55,534
    )Retained
      earnings
    
    
    
    
    
    37,665
    
    
    43,271Total common
      stockholder's equity
    
    
    
    
    
    3,149,797
    
    
    3,155,362Preferred
      stock
    
    
    
    
    
    12,649
    
    
    12,649Long-term debt
      and other long-term obligations
    
    
    
    
    
    1,229,210
    
    
    1,238,9844,391,656
    
    
    4,406,995**CURRENT
      LIABILITIES:**Currently
      payable long-term debt
    
    
    
    
    
    22,381
    
    
    16,866Notes
      payable-Associated
      companies
    
    
    
    
    
    204,794
    
    
    248,532Accounts
      payable-Associated
      companies
    
    
    
    
    
    9,248
    
    
    20,605Other
    
    
    
    
    
    105,699
    
    
    124,733Accrued
      taxes
    
    
    
    
    
    41,503
    
    
    2,626Accrued
      interest
    
    
    
    
    
    25,078
    
    
    10,359Other
    
    
    
    
    
    68,192
    
    
    65,130476,895
    
    
    488,851**NONCURRENT
      LIABILITIES:**Power purchase
      contract loss liability
    
    
    
    
    
    1,325,786
    
    
    1,268,478Accumulated
      deferred income taxes
    
    
    
    
    
    688,248
    
    
    645,741Nuclear fuel
      disposal costs
    
    
    
    
    
    171,014
    
    
    169,884Asset
      retirement obligation
    
    
    
    
    
    73,754
    
    
    72,655Retirement
      benefits
    
    
    
    
    
    98,307
    
    
    103,036Other
    
    
    
    
    
    139,443
    
    
    135,5442,496,552
    
    
    2,395,338**COMMITMENTS
      AND CONTINGENCIES (Note 12)**$
    7,365,103
    
    $
    7,291,184The preceding
      Notes to Consolidated Financial Statements as they relate to Jersey
      Central Power & Light Company are an integral part of these balance
      sheets.
   96
   **JERSEY
      CENTRAL POWER & LIGHT COMPANY****CONSOLIDATED
      STATEMENTS OF CASH FLOWS****(Unaudited)******
    
    **Three
      Months Ended****March
      31,****2005**
    
    **2004*****(In
      thousands)*****CASH
      FLOWS FROM OPERATING ACTIVITIES:**Net
      income
    
    
    
    
    $
    14,519
    
    $
    13,398Adjustments to
      reconcile net income to net cash from operating
activities-Provision for
      depreciation
    
    
    
    
    
    20,206
    
    
    19,075Amortization
      of regulatory assets
    
    
    
    
    
    68,374
    
    
    64,485Deferred
      costs, net
    
    
    
    
    
    (73,359
    )
    
    (37,981
    )Deferred
      income taxes and investment tax credits, net
    
    
    
    
    
    7,169
    
    
    230Accrued
      retirement benefit obligation
    
    
    
    
    
    (4,728
    )
    
    (11,714
    )Accrued
      compensation, net
    
    
    
    
    
    5,413
    
    
    (855
    )Decrease
      (Increase) in operating assets:Receivables
    
    
    
    
    
    14,849
    
    
    1,438Materials and
      supplies
    
    
    
    
    
    82
    
    
    358Prepayments
      and other current assets
    
    
    
    
    
    9,250
    
    
    24,376Increase
      (Decrease) in operating liabilities:Accounts
      payable
    
    
    
    
    
    (30,390
    )
    
    (15,349
    )Accrued
      taxes
    
    
    
    
    
    38,877
    
    
    49,480Accrued
      interest
    
    
    
    
    
    14,719
    
    
    10,778Other
    
    
    
    
    
    12,321
    
    
    4,323Net cash
      provided from operating activities
    
    
    
    
    
    97,302
    
    
    122,042**CASH
      FLOWS FROM FINANCING ACTIVITIES:**Redemptions
      and Repayments-Long-term
      debt
    
    
    
    
    
    (3,883
    )
    
    (3,591
    )Short-term
      borrowings, net
    
    
    
    
    
    (43,738
    )
    
    (79,744
    )Dividend
      Payments-Common
      stock
    
    
    
    
    
    (20,000
    )
    
    (5,000
    )Preferred
      stock
    
    
    
    
    
    (125
    )
    
    (125
    )Net cash used
      for financing activities
    
    
    
    
    
    (67,746
    )
    
    (88,460
    )**CASH
      FLOWS FROM INVESTING ACTIVITIES:**Property
      additions
    
    
    
    
    
    (28,124
    )
    
    (28,212
    )Loans to
      associated companies, net
    
    
    
    
    
    (898
    )
    
    (1,056
    )Other
    
    
    
    
    
    (655
    )
    
    (4,303
    )Net cash used
      for investing activities
    
    
    
    
    
    (29,677
    )
    
    (33,571
    )Net increase
      (decrease) in cash and cash equivalents
    
    
    
    
    
    (121
    )
    
    11Cash and cash
      equivalents at beginning of period
    
    
    
    
    
    162
    
    
    271Cash and cash
      equivalents at end of period
    
    
    
    
    $
    41
    
    $
    282The preceding
      Notes to Consolidated Financial Statements as they relate to Jersey
      Central Power & Light Company are an integral part ofthese
      statements.
    97









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





























To the Stockholders
and Board of


Directors of Jersey
Central


Power & Light
Company:





We have reviewed the
accompanying consolidated balance sheet of Jersey Central Power & Light
Company and its subsidiaries as of March 31, 2005, and the related
consolidated statements of income, comprehensive income and cash flows for each
of the three-month periods ended March 31, 2005 and 2004. These interim
financial statements are the responsibility of the Company’s
management.





We conducted our
review in accordance with the standards of the Public Company Accounting
Oversight Board (United States). A review of interim financial information
consists principally of applying analytical procedures and making inquiries of
persons responsible for financial and accounting matters. It is substantially
less in scope than an audit conducted in accordance with the standards of the
Public Company Accounting Oversight Board, the objective of which is the
expression of an opinion regarding the financial statements taken as a whole.
Accordingly, we do not express such an opinion.





Based on our review,
we are not aware of any material modifications that should be made to the
accompanying consolidated interim financial statements for them to be in
conformity with accounting principles generally accepted in the United States of
America.





We previously
audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheet as of
December 31, 2004, and the related consolidated statements of income,
capitalization, common stockholder’s equity, preferred stock, cash flows and
taxes for the year then ended, management’s assessment of the effectiveness of
the Company’s internal control over financial reporting as of December 31,
2004 and the effectiveness of the Company’s internal control over financial
reporting as of December 31, 2004; and in our report (which contained
references to the Company’s change in its method of accounting for asset
retirement obligations as of January 1, 2003 as discussed in Note 9 to
those consolidated financial statements and the Company’s change in its method
of accounting for the consolidation of variable interest entities as of
December 31, 2003 as discussed in Note 6 to those consolidated financial
statements) dated March 7, 2005, we expressed unqualified opinions thereon.
The consolidated financial statements and management’s assessment of the
effectiveness of internal control over financial reporting referred to above are
not presented herein. In our opinion, the information set forth in the
accompanying consolidated balance sheet information as of December 31,
2004, is fairly stated in all material respects in relation to the consolidated
balance sheet from which it has been derived.














PricewaterhouseCoopers
LLP


Cleveland,
Ohio


May 3,
2005











98





**JERSEY
CENTRAL POWER & LIGHT COMPANY**





**MANAGEMENT’S
DISCUSSION AND**


**ANALYSIS OF
RESULTS OF OPERATIONS**


**AND
FINANCIAL CONDITION**








JCP&L is a
wholly owned, electric utility subsidiary of FirstEnergy. JCP&L conducts
business in New Jersey, providing regulated electric transmission and
distribution services. JCP&L also provides generation services to those
customers electing to retain JCP&L as their power supplier. JCP&L has
restructured its electric rates in unbundled service charges and transition cost
recovery charges. JCP&L continues to deliver power to homes and businesses
through its existing distribution system.





**Results
of Operations**





Earnings on common
stock in the first quarter of 2005 increased to $14 million from $13 million in
2004, principally due to higher operating revenues, partially offset by
increases in other operating, purchased power costs and regulatory asset
amortization.





Operating revenues
increased $31 million or 6.2% in the first quarter of 2005 compared with 2004.
The higher revenues primarily resulted from increases in retail electric
generation sales of $18 million and distribution revenues of $12 million
partially offset by a $4 million decline in wholesale revenues.





The higher revenues
from generation sales to residential and commercial customers (residential - $14
million and commercial - $9 million) were due to increases in sales volume
(residential - 13.2% and commercial - 9.2%) and higher unit prices discussed
below. The sales volume increase was primarily due to lower customer shopping.
Generation provided by alternative suppliers as a percent of total sales
delivered in JCP&L’s service area decreased by 12.1 and 3.7 percentage
points for residential and commercial customers, respectively. A $5 million
decrease in industrial sales reflected the effect of increased customer shopping
which resulted in a 33.3% KWH sales decrease.





JCP&L's BGS
obligation has been transferred to external parties as a result of an NJBPU
auction process that extended the termination of JCP&L's BGS obligation
through May 2005 (see Outlook - Regulatory Matters). The higher unit prices
resulted from the BGS auction. The increased total retail generation KWH sales
reduced energy available for sale in the wholesale market which resulted in
lower wholesale sales revenues of $4 million (15.4% KWH sales decrease).





The increase in
distribution revenues in all customer sectors of $12 million in the first
quarter of 2005 compared to the first quarter of 2004 was primarily due to
higher composite unit prices. The 3.9% commercial sector KWH sales increase was
offset by minor declines in both the residential and industrial sectors.





The higher operating
revenues also reflected a $2 million payment received in the first quarter 2005
under a contract provision associated with the prior sale of TMI Unit 1. Under
the contract, additional payments are received if subsequent energy prices rise
above specified levels. This payment is credited to JCP&L’s customers,
resulting in no net earnings effect.





Changes in
kilowatt-hour sales by customer class in the first quarter of 2005 compared to
the first quarter of 2004 are summarized in the following table:





**Changes
      in Kilowatt-hour Sales**
    
    **2005*****Increase
      (Decrease******)***Electric
      Generation:Retail
    
    
    8.4
    %Wholesale
    
    
    (15.4
    )%**Total
      Electric Generation Sales**
    
    
    **2.3**
    **%**Distribution
      Deliveries:Residential
    
    
    (0.5
    )%Commercial
    
    
    3.9
    %Industrial
    
    
    (0.1
    )%**Total
      Distribution Deliveries**
    
    
    **1.4**
    **%**








99





*Operating
Expenses and Taxes*





Total operating
expenses and taxes increased $29 million in the first quarter of 2005 compared
to the prior year. Purchased power costs increased $6 million in the first
quarter of 2005 compared to 2004. The higher purchased power costs reflected
higher KWH purchased due to increased retail generation sales. The increase of
$14 million in other operating costs in the first quarter of 2005 compared to
2004 reflected in part the effects of a JCP&L labor strike. The JCP&L
labor strike, which affected approximately 1,300 employees, began on December 8,
2004 and lasted until March 15, 2005.





Amortization of
regulatory assets increased $4 million in the first quarter of 2005. The higher
amortization was caused by an increase in the level of MTC revenue
recovery.





***Capital
Resources and Liquidity***


JCP&L’s cash
requirements in 2005 for operating expenses, construction expenditures and
scheduled debt maturities are expected to be met with a combination of cash from
operations and funds from the capital markets. Thereafter, JCP&L expects to
meet its contractual obligations with cash from operations .


*Changes in Cash
Position*





As of March 31,
2005, JCP&L had $41,000 of cash and cash equivalents compared with $162,000
as of December 31, 2004. The major sources for changes in these balances
are summarized below.





*Cash Flows From
Operating Activities*





Cash provided from
operating activities in the first quarter of 2005 compared with the first
quarter of 2004, were as follows:








**Operating
      Cash Flows**
    
    **2005**
    
    **2004*****(In
      millions)***Cash earnings(1)
    
    $
    37
    
    $
    47Working
      capital and other
    
    
    60
    
    
    75Total Cash
      Flows from Operating Activities
    
    $
    97
    
    $
    122





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








Cash earnings (in
the table above) are not a measure of performance calculated in accordance with
GAAP. JCP&L believes that cash earnings is a useful financial measure
because it provides investors and management with an additional means of
evaluating its cash-based operating performance. The following table reconciles
cash earnings with net income.


**Reconciliation
      of Cash Earnings**
    
    **2005**
    
    **2004*****(In
      millions)***Net Income
      (GAAP)
    
    $
    15
    
    $
    13Non-Cash
      Charges (Credits):Provision for
      depreciation
    
    
    20
    
    
    19Amortization
      of regulatory assets
    
    
    68
    
    
    64Deferred costs
      recoverable as regulatory assets
    
    
    (73
    )
    
    (38
    )Deferred
      income taxes
    
    
    7
    
    
    --Other non-cash
      expenses
    
    
    --
    
    
    (11
    )Cash earnings
      (Non-GAAP)
    
    $
    37
    
    $
    47







The $10 million
decrease in cash earnings is described above and under "Results of Operations".
The $15 million decrease from working capital primarily resulted from changes in
prepayments and accounts payable of approximately $15 million each, partially
offset by a $13 million change in receivables.





100





***Cash
Flows From Financing Activities***





Net cash used for
financing activities decreased to $68 million in the first quarter of 2005 from
$88 million in same period of 2004. The decrease resulted from a $36 million
decrease in net debt redemptions partially offset by a $15 million increase in
common stock dividends to FirstEnergy.


JCP&L  had about $41,000 of
cash and temporary investments and approximately $205 million of short-term
indebtedness as of March 31, 2005. JCP&L has authorization from the SEC to
incur short-term debt up to its charter limit of $1.038 billion (including the
utility money pool). JCP&L will not issue FMB other than as collateral for
senior notes, since its senior note indentures prohibit (subject to certain
exceptions) JCP&L from issuing any debt which is senior to the senior notes.
As of March 31, 2005, JCP&L had the capability to issue $578 million of
additional senior notes based upon FMB collateral. As of March 31, 2005,
based upon applicable earnings coverage tests and its charter, JCP&L could
issue $564 million of preferred stock (assuming no additional debt was
issued).


JCP&L has the
ability to borrow from FirstEnergy and its regulated affiliates to meet its
short-term working capital requirements. FESC administers this money pool and
tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies
receiving a loan under the money pool agreements must repay the principal,
together with accrued interest, within 364 days of borrowing the funds. The rate
of interest is the same for each company receiving a loan from the pool and is
based on the average cost of funds available through the pool. The average
interest rate for borrowings in the first quarter of 2005 was 2.66%.





JCP&L’s access
to capital markets and costs of financing are dependent on the ratings of its
securities and the securities of FirstEnergy. The ratings outlook from the
rating agencies on all such securities is stable.





On March 18,
2005, S&P stated that FirstEnergy’s Sammis NSR settlement was a very
favorable step for FirstEnergy, although it would not immediately affect
FirstEnergy’s ratings or outlook. S&P noted that it continues to monitor the
refueling outage at the Perry nuclear plant, which includes a detailed
inspection by the NRC, and that if FirstEnergy should exit the outage without
significant negative findings or delays the ratings outlook would be revised to
positive.





*Cash Flows From
Investing Activities*





Net cash used in
investing activities was $30 million in the first quarter of 2005 compared to
$34 million in the previous year. The $4 million decrease primarily resulted
from a $4 million decrease in property removal costs.





During the last
three quarters of 2005, capital requirements for property additions and
improvements are expected to be about $150 million.





JCP&L’s capital
spending for the period 2005-2007 is expected to be about $511 million for
property additions, of which approximately $178 million applies to 2005.





**Market Risk
Information**





JCP&L uses
various market risk sensitive instruments, including derivative contracts,
primarily to manage the risk of price fluctuations. Its Risk Policy Committee,
comprised of members of senior management, provides general management oversight
to risk management activities throughout JCP&L. They are responsible for
promoting the effective design and implementation of sound risk management
programs. They also oversee compliance with corporate risk management policies
and established risk management practices.





*Commodity Price
Risk*





JCP&L is exposed
to market risk primarily due to fluctuations in electricity and natural gas
prices. To manage the volatility relating to these exposures, it uses a variety
of non-derivative and derivative instruments, including forward contracts,
options and futures contracts. The derivatives are used for hedging purposes.
Most of its non-hedge derivative contracts represent non-trading positions that
do not qualify for hedge treatment under SFAS 133. As of March 31, 2005
JCP&L had commodity derivative contracts with a fair value of $14 million. A
decrease of $1 million in the value of this asset was recorded as a decrease in
a regulatory liability and, therefore, had no impact on net income.





101








The valuation of
derivative contracts is based on observable market information to the extent
that such information is available. In cases where such information is not
available, we rely on model-based information. The model provides estimates of
future regional prices for electricity and an estimate of related price
volatility. JCP&L uses these results to develop estimates of fair value for
financial reporting purposes and for internal management decision making. The
valuation of the derivative contract at March 31, 2005 uses prices from
sources shown in the following table:




**Source of
Information - Fair Value by Contract Year**





**2005**
    
    **2006**
    
    **2007**
    
    **2008**
    
    **Thereafter**
    
    **Total*****(In
      millions)***Other external
      sources(1)
    
    $
    3
    
    $
    3
    
    $
    --
    
    $
    --
    
    $
    --
    
    $
    6Prices based
      on models
    
    
    --
    
    
    --
    
    
    2
    
    
    2
    
    
    4
    
    
    8**Total**(2)
    
    **$**
    **3**
    
    **$**
    **3**
    
    **$**
    **2**
    
    **$**
    **2**
    
    **$**
    **4**
    
    **$**
    **14**





(1)  Broker quote sheets.


(2)  Includes $14 million
from an embedded option that is offset by a regulatory liability and does not
affect earnings.





JCP&L performs
sensitivity analyses to estimate its exposure to the market risk of its
commodity position. A hypothetical 10% adverse shift in quoted market prices in
the near term on derivative instruments would not have had a material effect on
its consolidated financial position or cash flows as of March  31,
2005.





**Equity
Price Risk**




Included in nuclear
decommissioning trusts are marketable equity securities carried at their current
fair value of approximately $78 million and $80 million at March 31, 2005
and December 31, 2004, respectively. A hypothetical 10% decrease in prices
quoted by stock exchanges would result in an $8 million reduction in fair value
as of March 31, 2005.





**Outlook**





The electric industry continues to transition to a more competitive environment
and all ot JCP&L's customers can select alternative energy suppliers.
JCP&L continues to deliver power to residential homes and businesses through
its existing distribution system, which remains regulated. Customer rates have
been restructured into separate components to support customer choice. Adopting
new approaches to regulation and experiencing new forms of competition have
created new uncertainties.





*Regulatory
Matters*




Beginning in 1999,
all of JCP&L's customers had a choice for electric generation suppliers.
JCP&L's customer rates were restructured into unbundled service charges and
additional non-bypassable charges to recover stranded costs.





Regulatory assets
are costs which have been authorized by the NJBPU and the FERC for recovery from
customers in future periods and, without such authorization, would have been
charged to income when incurred. JCP&L's regulatory assets as of
March 31, 2005 and December 31, 2004 were $2.3 billion and $2.2
billion, respectively.





The July 2003 NJBPU
decision on JCP&L's base electric rate proceeding ordered a Phase II
proceeding be conducted to review whether JCP&L is in compliance with
current service reliability and quality standards. The NJBPU also ordered that
any expenditures and projects undertaken by JCP&L to increase its system's
reliability be reviewed as part of the Phase II proceeding, to determine their
prudence and reasonableness for rate recovery. In that Phase II proceeding, the
NJBPU could increase JCP&L’s return on equity to 9.75% or decrease it to
9.25%, depending on its assessment of the reliability of JCP&L's service.
Any reduction would be retroactive to August 1, 2003. On July 16,
2004, JCP&L filed the Phase II petition and testimony with the NJBPU,
requesting an increase in base rates of $36 million for the recovery of system
reliability costs and a 9.75% return on equity. The filing also requests an
increase to the MTC deferred balance recovery of approximately $20 million
annually. The Ratepayer Advocate filed testimony on November 16, 2004, and
JCP&L submitted rebuttal testimony on January 4, 2005. The Ratepayer
Advocate surrebuttal testimony was submitted February 8, 2005. Discovery
and settlement conferences are ongoing.





102





In accordance with
an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7,
2004 supporting a continuation of the current level and duration of the funding
of TMI-2 decommissioning costs by New Jersey customers without a reduction,
termination or capping of the funding. On September 30, 2004, JCP&L
filed an updated TMI-2 decommissioning study. This study resulted in an updated
total decommissioning cost estimate of $729 million (in 2003 dollars) compared
to the estimated $528 million (in 2003 dollars) from the prior 1995
decommissioning study. The Ratepayer Advocate filed comments on
February 28, 2005. On March 18, 2005, JCP&L filed a response to
those comments. A schedule for further proceedings has not yet been
set.


As a result of
outages experienced in JCP&L's service area in 2002 and 2003, the NJBPU had
implemented reviews into JCP&L's service reliability. On March 29,
2004, the NJBPU adopted a Memorandum of Understanding (MOU) that set out
specific tasks related to service reliability to be performed by JCP&L and a
timetable for completion and endorsed JCP&L's ongoing actions to implement
the MOU. On June 9, 2004, the NJBPU approved a Stipulation that
incorporates the final report of an SRM who made recommendations on appropriate
courses of action necessary to ensure system-wide reliability and the Executive
Summary and Recommendation portions of the final report of a focused audit of
JCP&L's Planning and Operations and Maintenance programs and practices
(Focused Audit). A Final Order in the Focused Audit docket was issued by the
NJBPU on July 23, 2004. On February 11, 2005, JCP&L met with the
Ratepayer Advocate to discuss reliability improvements. JCP&L continues to
file compliance reports reflecting activities associated with the MOU and
Stipulation.





See Note 13 to the
consolidated financial statements for further details and a complete discussion
of regulatory matters in New Jersey.





*Employee
Matters*




On March 15,
2005, members of the International Brotherhood of Electrical Workers System
Council U-3 ratified a new four-year contract with JCP&L. Ratification of
the contract resolved issues surrounding health care and work rules, and ended a
14-week strike against JCP&L by the Council’s members.





*Environmental
Matters*





JCP&L accrues
environmental liabilities only when it concludes that it is probable that it has
an obligation for such costs and can reasonably determine the amount of such
costs. Unasserted claims are reflected in JCP&L’s determination of
environmental liabilities and are accrued in the period that they are both
probable and reasonably estimable.





JCP&L has been
named as a PRP at waste disposal sites, which may require cleanup under the
Comprehensive Environmental Response, Compensation and Liability Act of 1980.
Allegations of disposal of hazardous substances at historical sites and the
liability involved are often unsubstantiated and subject to dispute; however,
federal law provides that all PRPs for a particular site are liable on a joint
and several basis. Therefore, environmental liabilities that are considered
probable have been recognized on the Consolidated Balance Sheet as of
March 31, 2005, based on estimates of the total costs of cleanup,
JCP&L's proportionate responsibility for such costs and the financial
ability of other nonaffiliated entities to pay. In addition, JCP&L has
accrued liabilities for environmental remediation of former manufactured gas
plants in New Jersey; those costs are being recovered by JCP&L through a
non-bypassable SBC. Included in Other Noncurrent Liabilities are accrued
liabilities aggregating approximately $47 million as of March 31,
2005.





*Other Legal
Proceedings*





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


In July 1999, the
Mid-Atlantic States experienced a severe heat wave, which resulted in power
outages throughout the service territories of many electric utilities, including
JCP&L's territory. In an investigation into the causes of the outages and
the reliability of the transmission and distribution systems of all four of New
Jersey’s electric utilities, the NJBPU concluded that there was not a prima
facie case demonstrating that, overall, JCP&L provided unsafe, inadequate or
improper service to its customers. Two class action lawsuits (subsequently
consolidated into a single proceeding) were filed in New Jersey Superior Court
in July 1999 against JCP&L, GPU and other GPU companies, seeking
compensatory and punitive damages arising from the July 1999 service
interruptions in the JCP&L territory.


103





In August 2002, the
trial court granted partial summary judgment to JCP&L and dismissed the
plaintiffs' claims for consumer fraud, common law fraud, negligent
misrepresentation, and strict product liability. In November 2003, the trial
court granted JCP&L's motion to decertify the class and denied plaintiffs'
motion to permit into evidence their class-wide damage model indicating damages
in excess of $50 million. These class decertification and damage rulings were
appealed to the Appellate Division. The Appellate Court issued a decision on
July 8, 2004, affirming the decertification of the originally certified
class, but remanding for certification of a class limited to those customers
directly impacted by the outages of transformers in Red Bank, New Jersey. On
September 8, 2004, the New Jersey Supreme Court denied the motions filed by
plaintiffs and JCP&L for leave to appeal the decision of the Appellate
Court. JCP&L has filed a motion for summary judgment. FirstEnergy is unable
to predict the outcome of these matters and no liability has been accrued as of
March 31, 2005.


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. The U.S. - Canada Power System Outage Task Force’s
final report in April 2004 on the outages 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 contained 46
"recommendations to prevent or minimize the scope of future blackouts."
Forty-five of those recommendations related to broad industry or policy matters
while one, including subparts, related to activities the Task Force recommended
be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the
causes of the August 14, 2003 power outages. FirstEnergy implemented
several initiatives, both prior to and since the August 14, 2003 power
outages, which were independently verified by NERC as complete in 2004 and were
consistent with these and other recommendations and collectively enhance the
reliability of its electric system. 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 completed in 2004 had a material effect on its
continuing 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 March 31, 2005 for any expenditures in excess
of those actually incurred through that date.


One complaint was
filed on August 25, 2004 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.





**New
Accounting Standards and Interpretations**





*FIN 47, “Accounting for Conditional Asset Retirement
Obligations - an interpretation of FASB Statement No. 143”*





On March 30,
2005, the FASB issued this interpretation to clarify the scope and timing of
liability recognition for conditional asset retirement obligations. Under this
interpretation, companies are required to recognize a liability for the fair
value of an asset retirement obligation that is conditional on a future event,
if the fair value of the liability can be reasonably estimated. In instances
where there is insufficient information to estimate the liability, the
obligation is to be recognized in the first period in which sufficient
information becomes available to estimate its fair value. If the fair value
cannot be reasonably estimated, that fact and the reasons why must be disclosed.
This interpretation is effective no later than the end of fiscal years ending
after December 15, 2005. FirstEnergy is currently evaluating the effect
this standard will have on the financial statements.





104





*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, FirstEnergy will continue
to evaluate its investments as required by existing authoritative
guidance.





105





**METROPOLITAN
      EDISON COMPANY****CONSOLIDATED
      STATEMENTS OF INCOME AND COMPREHENSIVE
      INCOME****(Unaudited)******
    
    **Three
      Months Ended****March
      31,****2005**
    
    **2004*****(In
      thousands)*****OPERATING
      REVENUES**
    
    
    
    
    $
    295,781
    
    $
    260,898**OPERATING
      EXPENSES AND TAXES:**Fuel and
      purchased power
    
    
    
    
    
    150,133
    
    
    143,456Other
      operating costs
    
    
    
    
    
    58,430
    
    
    33,048Provision for
      depreciation
    
    
    
    
    
    11,521
    
    
    9,898Amortization
      of regulatory assets
    
    
    
    
    
    28,621
    
    
    25,497General
      taxes
    
    
    
    
    
    19,272
    
    
    17,736Income
      taxes
    
    
    
    
    
    6,732
    
    
    7,980Total
      operating expenses and taxes
    
    
    
    
    
    274,709
    
    
    237,615**OPERATING
      INCOME**
    
    
    
    
    
    21,072
    
    
    23,283**OTHER
      INCOME (net of income taxes)**
    
    
    
    
    
    6,449
    
    
    5,526**NET
      INTEREST CHARGES:**Interest on
      long-term debt
    
    
    
    
    
    9,560
    
    
    10,147Allowance for
      borrowed funds used during construction
    
    
    
    
    
    (178
    )
    
    (71
    )Other interest
      expense
    
    
    
    
    
    1,663
    
    
    689Net interest
      charges
    
    
    
    
    
    11,045
    
    
    10,765**NET
      INCOME**
    
    
    
    
    $
    16,476
    
    $
    18,044**OTHER
      COMPREHENSIVE INCOME (LOSS):**Unrealized
      gain (loss) on derivative hedges
    
    
    
    
    
    84
    
    
    (3,260
    )Unrealized
      gain on available for sale securities
    
    
    
    
    
    --
    
    
    22Other
      comprehensive income (loss)
    
    
    
    
    
    84
    
    
    (3,238
    )Income tax
      related to other comprehensive income
    
    
    
    
    
    (35
    )
    
    (9
    )Other
      comprehensive income (loss), net of tax
    
    
    
    
    
    49
    
    
    (3,247
    )**TOTAL
      COMPREHENSIVE INCOME**
    
    
    
    
    $
    16,525
    
    $
    14,797The preceding
      Notes to Consolidated Financial Statements as they relate to Metropolitan
      Edison Company are an integral part of these
      statements.
   106
   **METROPOLITAN
      EDISON COMPANY****CONSOLIDATED
      BALANCE SHEETS****(Unaudited)****March
      31,**
    
    **December
      31,****2005**
    
    **2004*****(In
      thousands)*****ASSETS****UTILITY
      PLANT:**In
      service
    
    
    
    
    $
    1,796,340
    
    $
    1,800,569Less -
      Accumulated provision for depreciation
    
    
    
    
    
    697,927
    
    
    709,8951,098,413
    
    
    1,090,674Construction
      work in progress
    
    
    
    
    
    19,714
    
    
    21,7351,118,127
    
    
    1,112,409**OTHER
      PROPERTY AND INVESTMENTS:**Nuclear plant
      decommissioning trusts
    
    
    
    
    
    216,061
    
    
    216,951Long-term
      notes receivable from associated companies
    
    
    
    
    
    10,775
    
    
    10,453Other
    
    
    
    
    
    28,899
    
    
    34,767255,735
    
    
    262,171**CURRENT
      ASSETS:**Cash and cash
      equivalents
    
    
    
    
    
    120
    
    
    120Notes
      receivable from associated companies
    
    
    
    
    
    21,570
    
    
    18,769Receivables-Customers
      (less accumulated provisions of $4,418,000 and $4,578,000,respectively,
      for uncollectible accounts)
    
    
    
    
    
    126,303
    
    
    119,858Associated
      companies
    
    
    
    
    
    42,649
    
    
    118,245Other (less
      accumulated provision of $29,000 for uncollectible accounts in
      2005)
    
    
    
    
    
    14,932
    
    
    15,493Prepayments
      and other
    
    
    
    
    
    45,192
    
    
    11,057250,766
    
    
    283,542**DEFERRED
      CHARGES:**Goodwill
    
    
    
    
    
    867,769
    
    
    869,585Regulatory
      assets
    
    
    
    
    
    750,244
    
    
    693,133Other
    
    
    
    
    
    24,140
    
    
    24,4381,642,153
    
    
    1,587,156$
    3,266,781
    
    $
    3,245,278**CAPITALIZATION
      AND LIABILITIES****CAPITALIZATION:**Common
      stockholder's equity-Common stock,
      without par value, authorized 900,000 shares -859,500 shares
      outstanding
    
    
    
    
    $
    1,289,943
    
    $
    1,289,943Accumulated
      other comprehensive loss
    
    
    
    
    
    (43,441
    )
    
    (43,490
    )Retained
      earnings
    
    
    
    
    
    46,442
    
    
    38,966Total common
      stockholder's equity
    
    
    
    
    
    1,292,944
    
    
    1,285,419Long-term debt
      and other long-term obligations
    
    
    
    
    
    694,214
    
    
    701,7361,987,158
    
    
    1,987,155**CURRENT
      LIABILITIES:**Currently
      payable long-term debt
    
    
    
    
    
    37,395
    
    
    30,435Short-term
      borrowings-Associated
      companies
    
    
    
    
    
    108,677
    
    
    80,090Accounts
      payable-Associated
      companies
    
    
    
    
    
    30,959
    
    
    88,879Other
    
    
    
    
    
    34,426
    
    
    26,097Accrued
      taxes
    
    
    
    
    
    2,286
    
    
    11,957Accrued
      interest
    
    
    
    
    
    10,445
    
    
    11,618Other
    
    
    
    
    
    17,741
    
    
    23,076241,929
    
    
    272,152**NONCURRENT
      LIABILITIES:**Accumulated
      deferred income taxes
    
    
    
    
    
    314,193
    
    
    305,389Accumulated
      deferred investment tax credits
    
    
    
    
    
    10,662
    
    
    10,868Power purchase
      contract loss liability
    
    
    
    
    
    393,825
    
    
    349,980Nuclear fuel
      disposal costs
    
    
    
    
    
    38,631
    
    
    38,408Asset
      retirement obligation
    
    
    
    
    
    134,964
    
    
    132,887Retirement
      benefits
    
    
    
    
    
    80,571
    
    
    82,218Other
    
    
    
    
    
    64,848
    
    
    66,2211,037,694
    
    
    985,971**COMMITMENTS
      AND CONTINGENCIES (Note 12)**$
    3,266,781
    
    $
    3,245,278The preceding
      Notes to Consolidated Financial Statements as they relate to Metropolitan
      Edison Company are an integral part of these balance
      sheets.
    107
   **METROPOLITAN
      EDISON COMPANY****CONSOLIDATED
      STATEMENTS OF CASH FLOWS****(Unaudited)******
    
    **Three
      Months Ended****March
      31,****2005**
    
    **2004*****(In
      thousands)*****CASH
      FLOWS FROM OPERATING ACTIVITIES:**Net
      income
    
    
    
    
    $
    16,476
    
    $
    18,044Adjustments to
      reconcile net income to net cash from operating
activities-Provision for
      depreciation
    
    
    
    
    
    11,521
    
    
    9,898Amortization
      of regulatory assets
    
    
    
    
    
    28,621
    
    
    25,497Deferred costs
      recoverable as regulatory assets
    
    
    
    
    
    (16,441
    )
    
    (16,792
    )Deferred
      income taxes and investment tax credits, net
    
    
    
    
    
    (11
    )
    
    2,433Accrued
      retirement benefit obligation
    
    
    
    
    
    (1,647
    )
    
    1,074Accrued
      compensation, net
    
    
    
    
    
    (1,723
    )
    
    (634
    )Decrease
      (Increase) in operating assets:Receivables
    
    
    
    
    
    69,712
    
    
    5,767Materials and
      supplies
    
    
    
    
    
    (18
    )
    
    18Prepayments
      and other current assets
    
    
    
    
    
    (34,117
    )
    
    (36,618
    )Increase
      (Decrease) in operating liabilities:Accounts
      payable
    
    
    
    
    
    (49,591
    )
    
    6,848Accrued
      taxes
    
    
    
    
    
    (9,671
    )
    
    (1,546
    )Accrued
      interest
    
    
    
    
    
    (1,173
    )
    
    (4,465
    )Other
    
    
    
    
    
    (9,134
    )
    
    (8,265
    )Net cash
      provided from operating activities
    
    
    
    
    
    2,804
    
    
    1,259**CASH
      FLOWS FROM FINANCING ACTIVITIES:**New
      Financing-Long-term
      debt
    
    
    
    
    
    --
    
    
    247,607Short-term
      borrowings, net
    
    
    
    
    
    28,587
    
    
    --Redemptions
      and Repayments-Long-term
      debt
    
    
    
    
    
    (435
    )
    
    (50,435
    )Short-term
      borrowings, net
    
    
    
    
    
    --
    
    
    (65,335
    )Dividend
      Payments-Common
      stock
    
    
    
    
    
    (9,000
    )
    
    (5,000
    )Net cash
      provided from financing activities
    
    
    
    
    
    19,152
    
    
    126,837**CASH
      FLOWS FROM INVESTING ACTIVITIES:**Property
      additions
    
    
    
    
    
    (16,199
    )
    
    (8,962
    )Contributions
      to nuclear decommissioning trusts
    
    
    
    
    
    (2,371
    )
    
    (2,371
    )Loans to
      associated companies, net
    
    
    
    
    
    (3,150
    )
    
    (116,802
    )Other
    
    
    
    
    
    (236
    )
    
    38Net
      cash used for investing activities
    
    
    
    
    
    (21,956
    )
    
    (128,097
    )Net increase
      (decrease) in cash and cash equivalents
    
    
    
    
    
    --
    
    
    (1
    )Cash and cash
      equivalents at beginning of period
    
    
    
    
    
    120
    
    
    121Cash and cash
      equivalents at end of period
    
    
    
    
    $
    120
    
    $
    120The preceding
      Notes to Consolidated Financial Statements as they relate to Metropolitan
      Edison Company are an integral part
      of these statements.
    108





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





























To the Stockholders
and Board of


Directors of
Metropolitan Edison Company:





We have reviewed the
accompanying consolidated balance sheet of Metropolitan Edison Company and its
subsidiaries as of March 31, 2005, and the related consolidated statements
of income, comprehensive income and cash flows for each of the three-month
periods ended March 31, 2005 and 2004. These interim financial statements
are the responsibility of the Company’s management.





We conducted our
review in accordance with the standards of the Public Company Accounting
Oversight Board (United States). A review of interim financial information
consists principally of applying analytical procedures and making inquiries of
persons responsible for financial and accounting matters. It is substantially
less in scope than an audit conducted in accordance with the standards of the
Public Company Accounting Oversight Board, the objective of which is the
expression of an opinion regarding the financial statements taken as a whole.
Accordingly, we do not express such an opinion.





Based on our review,
we are not aware of any material modifications that should be made to the
accompanying consolidated interim financial statements for them to be in
conformity with accounting principles generally accepted in the United States of
America.





We previously
audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheet as of
December 31, 2004, and the related consolidated statements of income,
capitalization, common stockholder’s equity, preferred stock, cash flows and
taxes for the year then ended, management’s assessment of the effectiveness of
the Company’s internal control over financial reporting as of December 31,
2004 and the effectiveness of the Company’s internal control over financial
reporting as of December 31, 2004; and in our report (which contained
references to the Company’s change in its method of accounting for asset
retirement obligations as of January 1, 2003 as discussed in Note 2(G) to
those consolidated financial statements and the Company’s change in its method
of accounting for the consolidation of variable interest entities as of
December 31, 2003 as discussed in Note 6 to those consolidated financial
statements) dated March 7, 2005, we expressed unqualified opinions thereon.
The consolidated financial statements and management’s assessment of the
effectiveness of internal control over financial reporting referred to above are
not presented herein. In our opinion, the information set forth in the
accompanying consolidated balance sheet information as of December 31,
2004, is fairly stated in all material respects in relation to the consolidated
balance sheet from which it has been derived.














PricewaterhouseCoopers
LLP


Cleveland,
Ohio


May 3,
2005











109





**METROPOLITAN
EDISON COMPANY**





**MANAGEMENT’S
DISCUSSION AND**


**ANALYSIS OF
RESULTS OF OPERATIONS**


**AND
FINANCIAL CONDITION**








Met-Ed is a wholly
owned, electric utility subsidiary of FirstEnergy. Met-Ed conducts business in
eastern Pennsylvania, providing regulated electric transmission and distribution
services. Met-Ed also provides generation service to those customers electing to
retain Met-Ed as their power supplier. Met-Ed has unbundled the price for
electricity into its component elements - including generation, transmission,
distribution and transition charges. Met-Ed continues to deliver power to homes
and businesses through its existing distribution system.





**Results
of Operations**





Net income in the
first quarter of 2005 decreased to $16 million from $18 million in the first
quarter of 2004. The decrease was due to increases in purchased power costs,
amortization of regulatory assets, other operating costs and general taxes. The
decrease was partially offset by increased operating revenues.





Operating revenues
increased by $35 million, or 13.4% in the first quarter of 2005 compared with
the first quarter of 2004. The higher revenues primarily resulted from increases
of retail generation electric sales of $15 million and distribution revenues of
$6 million. The higher generation sales revenues in all customer sectors
reflected the effect of a 10.1% KWH sales increase and higher composite unit
prices. The sales volume increase resulted from lower customer shopping due to
customers returning to Met-Ed as their generation supplier. Sales by alternative
suppliers as a percent of total sales delivered in Met-Ed’s franchise area
decreased by 18.2, 1.4 and 0.1 percentage points in the industrial, commercial
and residential sectors, respectively.





Revenues from
distribution throughput increased by $6 million. The higher revenues were due to
higher KWH deliveries (3.7% increase) and unit prices in the first quarter of
2005 as compared to the same period of 2004. Also contributing to the higher
operating revenues was a $10 million increase due to Met-Ed’s assumption of
transmission revenues (PJM congestion credit and FTR/ARR) from FES due to a
change in the power supply agreement in the second quarter of 2004, which also
resulted in higher transmission expenses discussed below. In addition, the
higher operating revenues in the first quarter of 2005 included a $4 million
payment received under a contract provision associated with the prior sale of
TMI Unit 1. Under the contract, additional payments are received if subsequent
energy prices rise above specified levels. This payment is credited to Met-Ed’s
customers, resulting in no net earnings effect.





Changes in KWH
deliveries in the first quarter of 2005 compared to the first quarter 2004 are
summarized in the following table:





**Changes
      in KWH****Increase
      (Decrease)**Residential
    
    
    2.2
    %Commercial
    
    
    5.4
    %Industrial
    
    
    3.9
    %**Total
      KWH Deliveries**
    
    
    **3.7**
    **%**





*Operating
Expenses and Taxes*





Total operating
expenses and taxes increased by $37 million in the first quarter of 2005 from
the first quarter of 2004. Purchased power costs increased in 2005 primarily due
to an $18 million increase in two-party power purchases and a $2 million
increase in NUG contract purchases, partially offset by a $14 million reduction
in power purchased from FES. The net increase in KWH purchases was attributable
to the increase in retail generation sales.





Other operating
costs increased in the first quarter of 2005 primarily due to $27 million higher
PJM ancillary transmission expenses, congestion charges, and FTR/ARR expenses.
The transmission expense increase resulted from Met-Ed’s assumption of PLR
transmission related transactions discussed above. Other operating costs also
increased due to higher storm-related and vegetation management
costs.





Depreciation
expenses increased due to higher estimated costs to decommission the Saxton
nuclear plant and depreciation expense on property purchased from FESC in late
2004. Amortization of regulatory assets increased primarily due to increased
amortization of regulatory assets being recovered through CTC rates, partially
offset by lower amortization related to above market NUG costs.





110





General taxes
increased by $2 million in the first quarter of 2005 due to higher gross receipt
taxes.





**Capital
Resources and Liquidity**





Met-Ed’s cash
requirements in 2005 and thereafter, for operating expenses, construction
expenditures and scheduled debt maturities are expected to be met with a
combination of cash from operations and funds from the capital
markets.





*Changes in Cash
Position*





As of March 31,
2005 and December 31, 2004, Met-Ed had $120,000 of cash and cash
equivalents.





*Cash Flows From
Operating Activities*





Cash provided from
operating activities in the first quarter of 2005 and 2004 were as
follows:








**Operating
      Cash Flows**
    
    **2005**
    
    **2004*****(In
      millions)***Cash earnings(1)
    
    $
    37
    
    $
    39Working
      capital and other
    
    
    (34
    )
    
    (38
    )Total Cash
      Flows from Operating Activities
    
    $
    3
    
    $
    1








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





Cash earnings (in
the table above) are not a measure of performance calculated in accordance with
GAAP. Met-Ed believes that cash earnings is a useful financial measure because
it provides investors and management with an additional means of evaluating its
cash-based operating performance.





**Three
      Months Ended****March
      31,****Reconciliation
      of Cash Earnings**
    
    **2005**
    
    **2004*****(In
      millions)***Net Income
      (GAAP)
    
    $
    16
    
    $
    18Non-Cash
      Charges (Credits):Provision for
      depreciation
    
    
    12
    
    
    10Amortization
      of regulatory assets
    
    
    29
    
    
    25Deferred costs
      recoverable as regulatory assets
    
    
    (16
    )
    
    (17
    )Deferred
      income taxes and investment tax credits, net
    
    
    --
    
    
    2Other non-cash
      expenses
    
    
    (4
    )
    
    1Cash earnings
      (Non-GAAP)
    
    $
    37
    
    $
    39





The $2 million
decrease in cash earnings is described above and under "Results of Operations".
The $4 million working capital change primarily resulted from changes of $64
million in receivables and $3 million in accrued interest, partially offset by
changes of $56 million in accounts payable and $8 million in accrued taxes.





*Cash Flows From
Financing Activities*





Net cash provided
from financing activities was $19 million in the first quarter of 2005 compared
to $127 million in the first quarter of 2004. The decrease primarily reflected
$29 million of short-term borrowings in the first quarter of 2005 compared to
last year’s issuance of $250 million of senior notes, partially offset by debt
redemptions of $115 million in the first quarter of 2004. In addition, common
stock dividends to FirstEnergy increased by $4 million in 2005.





As of March 31,
2005, Met-Ed had approximately $22 million of cash and temporary investments
(which included short-term notes receivable from associated companies) and $109
million of short-term borrowings outstanding. Met-Ed has authorization from the
SEC to incur short-term debt up to $250 million (including the utility money
pool). Under the terms of Met-Ed’s senior note indenture, no more first mortgage
bonds can be issued so long as the senior bonds are outstanding. Met-Ed had no
restrictions on the issuance of preferred stock.








111





In addition, Met-Ed
has an $80 million customer receivables financing facility. The facility was
undrawn as of March 31, 2005; it expires June 30, 2005 and is expected
to be renewed.





Met-Ed has the
ability to borrow from its regulated affiliates and FirstEnergy to meet its
short-term working capital requirements. FESC administers this money pool and
tracks surplus funds of FirstEnergy and its regulated subsidiaries, as well as
proceeds available from bank borrowings. Companies receiving a loan under the
money pool agreements must repay the principal amount of such a loan, together
with accrued interest, within 364 days of borrowing the funds. The rate of
interest is the same for each company receiving a loan from the pool and is
based on the average cost of funds available through the pool. The average
interest rate for borrowings in the first quarter of 2005 was
2.66%.





Met-Ed’s access to
capital markets and costs of financing are dependent on the ratings of its
securities and that of FirstEnergy. The ratings outlook on all securities is
stable.





On March 18,
2005, S&P stated that FirstEnergy’s Sammis NSR settlement was a very
favorable step for FirstEnergy, although it would not immediately affect
FirstEnergy’s ratings or outlook. S&P noted that it continues to monitor the
refueling outage at the Perry nuclear plant, which includes a detailed
inspection by the NRC, and that if FirstEnergy should exit the outage
without significant negative findings or delays the ratings outlook would be
revised to positive.





*Cash Flows From
Investing Activities*





In the first quarter
of 2005, net cash used in investing activities totaled $22 million, compared to
$128 million in the first quarter of 2004. The decrease resulted from a $114
million decrease in loans to associated companies offset in part by a $7 million
increase in property additions. Expenditures for property additions primarily
support Met-Ed’s energy delivery operations.





During the remaining
quarters of 2005, capital requirements for property additions are expected to be
about $52 million. Met-Ed has additional requirements of approximately $37
million for maturing long-term debt during the remainder of 2005. These cash
requirements are expected to be satisfied from internal cash and short-term
credit arrangements.





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





**Market
Risk Information**





Met-Ed uses various
market risk sensitive instruments, including derivative contracts, primarily to
manage the risk of price fluctuations. FirstEnergy’s Risk Policy Committee,
comprised of members of senior management, provides general management to risk
management activities throughout the Company.





*Commodity Price
Risk*





Met-Ed is exposed to
market risk primarily due to fluctuations in electricity and natural gas prices.
To manage the volatility relating to these exposures, it uses a variety of
non-derivative and derivative instruments, including options and futures
contracts. The derivatives are used for hedging purposes. Most of Met-Ed's
non-hedge derivative contracts represent non-trading positions that do not
qualify for hedge treatment under SFAS 133. As of March 31, 2005, Met-Ed’s
commodity derivative contract was an embedded option with a fair value of $27
million. A decrease of $5 million in the value of this asset was recorded as a
decrease in a regulatory liability and, therefore, had no impact on net
income.





The valuation of
derivative contracts is based on observable market information to the extent
that such information is available. In cases where such information is not
available, Met-Ed relies on model-based information. The model provides
estimates of future regional prices for electricity and an estimate of related
price volatility. Met-Ed uses these results to develop estimates of fair value
for financial reporting purposes and for internal management decision making.
The valuation of the derivative contract at March 31, 2005 is shown using
prices from sources in the following table:





**Source
      of Information****- Fair
      Value by Contract Year**
    
    **2005**
    
    **2006**
    
    **2007**
    
    **2008**
    
    **2009**
    
    **Thereafter**
    
    **Total*****(In
      millions)***Prices based
      on external sources(1)
    
    $
    5
    
    $
    4
    
    $
    --
    
    $
    --
    
    $
    --
    
    $
    --
    
    $
    9Prices based
      on models
    
    
    --
    
    
    --
    
    
    6
    
    
    5
    
    
    3
    
    
    4
    
    
    18**Total**
    
    **$**
    **5**
    
    **$**
    **4**
    
    **$**
    **6**
    
    **$**
    **5**
    
    **$**
    **3**
    
    **$**
    **4**
    
    **$**
    **27**


(1) Broker quote
sheets.





112




Met-Ed performs
sensitivity analyses to estimate its exposure to the market risk of its
commodity positions. A hypothetical 10% adverse shift in quoted market prices in
the near term on derivative instruments would not have had a material effect on
its consolidated financial position or cash flows as of March 31,
2005.





*Equity Price
Risk*





Included in Met-Ed's
nuclear decommissioning trust investments are marketable equity securities
carried at their market value of approximately $131 million and $134 million as
of March 31, 2005 and December 31, 2004, respectively. A hypothetical
10% decrease in prices quoted by stock exchanges would result in a $13 million
reduction in fair value as of March 31, 2005.





**OUTLOOK**





The electric industry continues to transition to a more competitive environment
and all of Met-Ed's customers can select alternative energy suppliers. Met-Ed
continues to deliver power to residential homes and businesses through its
existing distribution system, which remains regulated. Customer rates have been
restructured into separate components to support customer choice. Met-Ed has 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*




Beginning in 1999,
all of Met-Ed's customers had a choice for electric generation suppliers.
Met-Ed's customer rates were restructured to itemize (unbundle) the current
price of electricity into its component elements - including generation,
transmission, distribution and stranded cost recovery. In the event customers
obtain power from an alternative source, the generation portion of Met-Ed's
rates is excluded from their bill and the customers receive a generation charge
from the alternative supplier.





Regulatory assets
are costs which have been authorized by the PPUC and the FERC for recovery from
customers in future periods and, without such authorization, would have been
charged to income when incurred. Met-Ed's regulatory assets as of March 31,
2005 and December 31, 2004 were $750 million and $693 million, respectively.





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





On January 12,
2005, Met-Ed filed a request with the PPUC for deferral of transmission-related
costs beginning January 1, 2005, estimated to be approximately $4 million
per month.





See Note 13 to the
consolidated financial statements for further details and a complete discussion
of regulatory matters in Pennsylvania including a more detailed discussion of
reliability initiatives, including actions by the PPUC, that impacts
Met-Ed.





*Environmental
Matters*





Met-Ed accrues
environmental liabilities only when it concludes that it is probable that it has
an obligation for such costs and can reasonably determine the amount of such
costs. Unasserted claims are reflected in Met-Ed's determination of
environmental liabilities and are accrued in the period that they are both
probable and reasonably estimable.





113


Met-Ed has been
named a PRP at waste disposal sites, which may require cleanup under the
Comprehensive Environmental Response, Compensation and Liability Act of 1980.
Allegations of disposal of hazardous substances at historical sites and the
liability involved are often unsubstantiated and subject to dispute; however,
federal law provides that all PRPs for a particular site are liable on a joint
and several basis. Therefore, environmental liabilities that are considered
probable have been recognized on the Consolidated Balance Sheet as of
March 31, 2005, based on estimates of the total costs of cleanup, Met-Ed's
proportionate responsibility for such costs and the financial ability of other
nonaffiliated entities to pay. Included in Other Noncurrent Liabilities are
accrued liabilities aggregating approximately $48,000 as of March 31, 2005.


*Other Legal
Proceedings*





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




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. The U.S. - Canada Power System Outage Task Force’s
final report in April 2004 on the outages 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 contained 46
"recommendations to prevent or minimize the scope of future blackouts."
Forty-five of those recommendations related to broad industry or policy matters
while one, including subparts, related to activities the Task Force recommended
be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the
causes of the August 14, 2003 power outages. FirstEnergy implemented
several initiatives, both prior to and since the August 14, 2003 power
outages, which were independently verified by NERC as complete in 2004 and were
consistent with these and other recommendations and collectively enhance the
reliability of its electric system. 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 completed in 2004 had a material effect on its
continuing 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 March 31, 2005 for any expenditures in excess
of those actually incurred through that date.




One complaint was
filed on August 25, 2004 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.





114





**New
Accounting Standards and Interpretations**





*FIN 47, “Accounting for Conditional Asset Retirement
Obligations - an interpretation of FASB Statement No. 143”*





On March 30,
2005, the FASB issued this interpretation to clarify the scope and timing of
liability recognition for conditional asset retirement obligations. Under this
interpretation, companies are required to recognize a liability for the fair
value of an asset retirement obligation that is conditional on a future event,
if the fair value of the liability can be reasonably estimated. In instances
where there is insufficient information to estimate the liability, the
obligation is to be recognized in the first period in which sufficient
information becomes available to estimate its fair value. If the fair value
cannot be reasonably estimated, that fact and the reasons why must be disclosed.
This interpretation is effective no later than the end of fiscal years ending
after December 15, 2005. FirstEnergy is currently evaluating the effect
this standard will have 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, FirstEnergy will continue
to evaluate its investments as required by existing authoritative
guidance.








115





**PENNSYLVANIA
      ELECTRIC COMPANY****CONSOLIDATED
      STATEMENTS OF INCOME AND COMPREHENSIVE
      INCOME****(Unaudited)******
    
    **Three
      Months Ended****March
      31,****2005**
    
    **2004*****(In
      thousands)*****OPERATING
      REVENUES**
    
    
    
    
    $
    293,929
    
    $
    256,445**OPERATING
      EXPENSES AND TAXES:**Purchased
      power
    
    
    
    
    
    150,277
    
    
    156,376Other
      operating costs
    
    
    
    
    
    53,793
    
    
    39,908Provision for
      depreciation
    
    
    
    
    
    12,506
    
    
    11,438Amortization
      of regulatory assets
    
    
    
    
    
    13,185
    
    
    13,651General
      taxes
    
    
    
    
    
    18,206
    
    
    16,962Income
      taxes
    
    
    
    
    
    15,792
    
    
    2,563Total
      operating expenses and taxes
    
    
    
    
    
    263,759
    
    
    240,898**OPERATING
      INCOME**
    
    
    
    
    
    30,170
    
    
    15,547**OTHER
      INCOME (EXPENSE) (net of income taxes)**
    
    
    
    
    
    736
    
    
    (84
    )**NET
      INTEREST CHARGES:**Interest on
      long-term debt
    
    
    
    
    
    7,459
    
    
    7,447Allowance for
      borrowed funds used during construction
    
    
    
    
    
    (125
    )
    
    (70
    )Deferred
      interest
    
    
    
    
    
    --
    
    
    190Other interest
      expense
    
    
    
    
    
    2,188
    
    
    2,237Net interest
      charges
    
    
    
    
    
    9,522
    
    
    9,804**NET
      INCOME**
    
    
    
    
    $
    21,384
    
    $
    5,659**OTHER
      COMPREHENSIVE INCOME (LOSS):**Unrealized
      gain on derivative hedges
    
    
    
    
    
    16
    
    
    --Unrealized
      gain (loss) on available for sale securities
    
    
    
    
    
    (3
    )
    
    8Other
      comprehensive income (loss)
    
    
    
    
    
    13
    
    
    8Income tax
      related to other comprehensive income
    
    
    
    
    
    (6
    )
    
    (3
    )Other
      comprehensive income (loss), net of tax
    
    
    
    
    
    7
    
    
    5**TOTAL
      COMPREHENSIVE INCOME**
    
    
    
    
    $
    21,391
    
    $
    5,664The preceding
      Notes to Consolidated Financial Statements as they relate to Pennsylvania
      Electric Company are an integral
      part of these statements.
    116
  **PENNSYLVANIA
      ELECTRIC COMPANY****CONSOLIDATED
      BALANCE SHEETS****(Unaudited)****March
      31,**
    
    **December
      31,****2005**
    
    **2004*****(In
      thousands)*****ASSETS****UTILITY
      PLANT:**In
      service
    
    
    
    
    $
    1,962,547
    
    $
    1,981,846Less -
      Accumulated provision for depreciation
    
    
    
    
    
    756,126
    
    
    776,9041,206,421
    
    
    1,204,942Construction
      work in progress
    
    
    
    
    
    25,837
    
    
    22,8161,232,258
    
    
    1,227,758**OTHER
      PROPERTY AND INVESTMENTS:**Nuclear plant
      decommissioning trusts
    
    
    
    
    
    108,252
    
    
    109,620Non-utility
      generation trusts
    
    
    
    
    
    96,738
    
    
    95,991Long-term
      notes receivable from associated companies
    
    
    
    
    
    14,164
    
    
    14,001Other
    
    
    
    
    
    14,589
    
    
    18,746233,743
    
    
    238,358**CURRENT
      ASSETS:**Cash and cash
      equivalents
    
    
    
    
    
    35
    
    
    36Notes
      receivable from associated companies
    
    
    
    
    
    10,271
    
    
    7,352Receivables-Customers
      (less accumulated provisions of $4,435,000 and $4,712,000,respectively,
      for uncollectible accounts)
    
    
    
    
    
    128,530
    
    
    121,112Associated
      companies
    
    
    
    
    
    48,645
    
    
    97,528Other
    
    
    
    
    
    15,098
    
    
    12,778Prepayments
      and other
    
    
    
    
    
    42,317
    
    
    7,198244,896
    
    
    246,004**DEFERRED
      CHARGES:**Goodwill
    
    
    
    
    
    887,103
    
    
    888,011Regulatory
      assets
    
    
    
    
    
    277,520
    
    
    200,173Other
    
    
    
    
    
    12,293
    
    
    13,4481,176,916
    
    
    1,101,632$
    2,887,813
    
    $
    2,813,752**CAPITALIZATION
      AND LIABILITIES****CAPITALIZATION:**Common
      stockholder's equity-Common stock,
      $20 par value, authorized 5,400,000 shares -5,290,596
      shares outstanding
    
    
    
    
    $
    105,812
    
    $
    105,812Other paid-in
      capital
    
    
    
    
    
    1,205,948
    
    
    1,205,948Accumulated
      other comprehensive loss
    
    
    
    
    
    (52,806
    )
    
    (52,813
    )Retained
      earnings
    
    
    
    
    
    62,453
    
    
    46,068Total common
      stockholder's equity
    
    
    
    
    
    1,321,407
    
    
    1,305,015Long-term debt
      and other long-term obligations
    
    
    
    
    
    478,695
    
    
    481,8711,800,102
    
    
    1,786,886**CURRENT
      LIABILITIES:**Currently
      payable long-term debt
    
    
    
    
    
    11,525
    
    
    8,248Short-term
      borrowings-Associated
      companies
    
    
    
    
    
    69,693
    
    
    241,496Other
    
    
    
    
    
    170,000
    
    
    --Accounts
      payable-Associated
      companies
    
    
    
    
    
    28,338
    
    
    56,154Other
    
    
    
    
    
    29,542
    
    
    25,960Accrued
      taxes
    
    
    
    
    
    18,204
    
    
    7,999Accrued
      interest
    
    
    
    
    
    15,276
    
    
    9,695Other
    
    
    
    
    
    18,166
    
    
    23,750360,744
    
    
    373,302**NONCURRENT
      LIABILITIES:**Power purchase
      contract loss liability
    
    
    
    
    
    441,255
    
    
    382,548Asset
      retirement obligation
    
    
    
    
    
    67,482
    
    
    66,443Accumulated
      deferred income taxes
    
    
    
    
    
    49,680
    
    
    37,318Retirement
      benefits
    
    
    
    
    
    119,115
    
    
    118,247Other
    
    
    
    
    
    49,435
    
    
    49,008726,967
    
    
    653,564**COMMITMENTS
      AND CONTINGENCIES (Note 12)**$
    2,887,813
    
    $
    2,813,752The preceding
      Notes to Consolidated Financial Statements as they relate to Pennsylvania
      Electric Company are an integral part of these balance
    sheets.
   117
  **PENNSYLVANIA
      ELECTRIC COMPANY****CONSOLIDATED
      STATEMENTS OF CASH FLOWS****(Unaudited)******
    
    **Three
      Months Ended****March
      31,****2005**
    
    **2004*****(In
      thousands)*****CASH
      FLOWS FROM OPERATING ACTIVITIES:**Net
      income
    
    
    
    
    $
    21,384
    
    $
    5,659Adjustments to
      reconcile net income to net cash from operating
activities-Provision for
      depreciation
    
    
    
    
    
    12,506
    
    
    11,438Amortization
      of regulatory assets
    
    
    
    
    
    13,185
    
    
    13,651Deferred costs
      recoverable as regulatory assets
    
    
    
    
    
    (19,433
    )
    
    (17,993
    )Deferred
      income taxes and investment tax credits, net
    
    
    
    
    
    2,446
    
    
    25,242Accrued
      retirement benefit obligation
    
    
    
    
    
    868
    
    
    2,802Accrued
      compensation, net
    
    
    
    
    
    (2,630
    )
    
    2,255Decrease
      (Increase) in operating assets:Receivables
    
    
    
    
    
    39,145
    
    
    (12,129
    )Prepayments
      and other current assets
    
    
    
    
    
    (35,119
    )
    
    (47,054
    )Increase
      (Decrease) in operating liabilities:Accounts
      payable
    
    
    
    
    
    (24,234
    )
    
    (10,738
    )Accrued
      taxes
    
    
    
    
    
    10,205
    
    
    (6,483
    )Accrued
      interest
    
    
    
    
    
    5,581
    
    
    2,636Other
    
    
    
    
    
    (217
    )
    
    3,654Net cash
      provided from (used for) operating activities
    
    
    
    
    
    23,687
    
    
    (27,060
    )**CASH
      FLOWS FROM FINANCING ACTIVITIES:**New
      Financing-Long-term
      debt
    
    
    
    
    
    --
    
    
    150,000Redemptions
      and Repayments-Long-term
      debt
    
    
    
    
    
    (13
    )
    
    (104
    )Short-term
      borrowings, net
    
    
    
    
    
    (1,803
    )
    
    (61,326
    )Dividend
      Payments-Common
      stock
    
    
    
    
    
    (5,000
    )
    
    --Net cash
      provided from (used for) financing activities
    
    
    
    
    
    (6,816
    )
    
    88,570**CASH
      FLOWS FROM INVESTING ACTIVITIES:**Property
      additions
    
    
    
    
    
    (15,393
    )
    
    (11,194
    )Non-utility
      generation trust contribution
    
    
    
    
    
    --
    
    
    (50,614
    )Loans to
      associated companies, net
    
    
    
    
    
    (3,082
    )
    
    (71
    )Other,
      net
    
    
    
    
    
    1,603
    
    
    369Net cash used
      for investing activities
    
    
    
    
    
    (16,872
    )
    
    (61,510
    )Net change in
      cash and cash equivalents
    
    
    
    
    
    (1
    )
    
    --Cash and cash
      equivalents at beginning of period
    
    
    
    
    
    36
    
    
    36Cash and cash
      equivalents at end of period
    
    
    
    
    $
    35
    
    $
    36The preceding
      Notes to Consolidated Financial Statements as they relate to Pennsylvania
      Electric Company are an integral part
      of these statements.
   118







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





























To the Stockholders
and Board of


Directors of
Pennsylvania Electric Company:





We have reviewed the
accompanying consolidated balance sheet of Pennsylvania Electric Company and its
subsidiaries as of March 31, 2005, and the related consolidated statements
of income, comprehensive income and cash flows for each of the three-month
periods ended March 31, 2005 and 2004. These interim financial statements
are the responsibility of the Company’s management.





We conducted our
review in accordance with the standards of the Public Company Accounting
Oversight Board (United States). A review of interim financial information
consists principally of applying analytical procedures and making inquiries of
persons responsible for financial and accounting matters. It is substantially
less in scope than an audit conducted in accordance with the standards of the
Public Company Accounting Oversight Board, the objective of which is the
expression of an opinion regarding the financial statements taken as a whole.
Accordingly, we do not express such an opinion.





Based on our review,
we are not aware of any material modifications that should be made to the
accompanying consolidated interim financial statements for them to be in
conformity with accounting principles generally accepted in the United States of
America.





We previously
audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheet as of
December 31, 2004, and the related consolidated statements of income,
capitalization, common stockholder’s equity, preferred stock, cash flows and
taxes for the year then ended, management’s assessment of the effectiveness of
the Company’s internal control over financial reporting as of December 31,
2004 and the effectiveness of the Company’s internal control over financial
reporting as of December 31, 2004; and in our report (which contained
references to the Company’s change in its method of accounting for asset
retirement obligations as of January 1, 2003 as discussed in Note 2(G) to
those consolidated financial statements and the Company’s change in its method
of accounting for the consolidation of variable interest entities as of
December 31, 2003 as discussed in Note 6 to those consolidated financial
statements) dated March 7, 2005, we expressed unqualified opinions thereon.
The consolidated financial statements and management’s assessment of the
effectiveness of internal control over financial reporting referred to above are
not presented herein. In our opinion, the information set forth in the
accompanying consolidated balance sheet information as of December 31,
2004, is fairly stated in all material respects in relation to the consolidated
balance sheet from which it has been derived.














PricewaterhouseCoopers
LLP


Cleveland,
Ohio


May 3,
2005








119





**PENNSYLVANIA
ELECTRIC COMPANY**





**MANAGEMENT’S
DISCUSSION AND**


**ANALYSIS OF
RESULTS OF OPERATIONS**


**AND
FINANCIAL CONDITION**





Penelec is a wholly
owned electric utility subsidiary of FirstEnergy. Penelec conducts business in
northern, western and south central Pennsylvania, providing regulated
transmission and distribution services. Penelec also provides generation
services to those customers electing to retain Penelec as their power supplier.
Penelec has unbundled the price for electricity into its component elements -
including generation, transmission, distribution and transition
charges.





**Results
of Operations**





Net income in the
first quarter of 2005 increased to $21 million, compared to $6 million in the
first quarter of 2004. The increase resulted from higher operating revenues and
lower purchased power costs, partially offset by higher other operating costs
and general taxes.





Operating revenues
increased by $37 million in the first quarter of 2005 compared to the first
quarter of 2004, primarily due to higher transmission, retail generation and
distribution revenues. T ransmission revenues
increased $23 million as a result of Penelec's assumption of transmission
revenues from FES due to a change in the power supply agreement with FES in the
second quarter of 2004, which also resulted in higher transmission expenses
discussed further below. In addition, the higher first quarter 2005 operating
revenues included a $2 million payment received under a contract provision
associated with the prior sale of TMI Unit 1. Under the contract, additional
payments are received if subsequent energy prices rise above specified levels.
This payment is credited to Penelec’s customers, resulting in no net earnings
effect.





Retail generation
revenues increased by $9 million, principally from increased generation sales to
industrial and commercial customers (industrial - $5 million and commercial - $4
million) reflecting volume sales increases of 12.5% and 6.8%, respectively, and
higher unit costs. Industrial KWH sales increased despite higher customer
shopping in this sector. Sales by alternative suppliers as a percent of total
industrial sales delivered in Penelec’s franchise area increased by 4.0
percentage points, while commercial customer shopping remained constant in the
first quarter of 2005. Residential generation revenues showed a slight increase
of $0.4 million and residential KWH sales were nearly unchanged in the first
quarter of 2005 as compared to last year.





Distribution
revenues increased by $3 million in the first quarter of 2005 as compared to the
same period of 2004, primarily on higher deliveries to the commercial and
industrial sectors. The higher commercial and industrial revenues of $2 million
and $1 million, respectively, reflected the effect of increased KWH deliveries
partially offset by lower composite unit prices.





Changes in electric
distribution deliveries in the first quarter 2005 compared to the first quarter
2004 are summarized in the following table:








**Changes
      in KWH Deliveries**
    
    **2005*****Increase
      (Decrease)***Residential
    
    
    0.5
    %Commercial
    
    
    6.9
    %Industrial
    
    
    18.4
    %**Total
      KWH Deliveries**
    
    
    **8.0**
    **%**





*Operating
Expenses and Taxes*




Total operating
expenses and taxes increased by $23 million or 9.5% in the first quarter 2005
from the first quarter of 2004. Purchased power costs decreased by $6 million or
3.9% in the first quarter of 2005, compared to the first quarter 2004. The
decrease was due primarily to lower unit costs slightly offset by increased KWH
purchased to meet increased retail generation sales requirements. Other
operating costs increased by $14 million or 34.8% in the first quarter 2005,
compared to first quarter 2004. That increase was primarily due to increased
transmission expenses in 2005, which were assumed by Penelec due to a change in
the power supply agreement with FES discussed above. In addition, there were
higher storm-related contractor costs in the first quarter of 2005.





120




General taxes
increased due to the higher Pennsylvania gross receipts taxes in first quarter
of 2005 compared to same period in 2004. Income taxes increased due to higher
pre-tax income in the first quarter of 2005 compared to the first quarter of
2004.





**Capital
Resources and Liquidity**





Penelec’s cash
requirements in 2005 and thereafter, for operating expenses, construction
expenditures and scheduled debt maturities are expected to be met by a
combination of cash from operations and funds from the capital markets.





*Changes in Cash
Position*




As of March 31,
2005, Penelec had $35,000 of cash and cash equivalents compared with $36,000 as
of December 31, 2004. The major sources for changes in these balances are
summarized below.





*Cash Flows From
Operating Activities*





Net cash provided
from operating activities was $24 million in the first quarter of 2005, compared
to net cash used for operating activities of $27 million in 2004, summarized as
follows:








**Operating
      Cash Flows**
    
    **2005**
    
    **2004*****(In
      millions)***Cash earnings(1)
    
    $
    28
    
    $
    43Working
      capital and other
    
    
    (4
    )
    
    (70
    )**Total**
    
    **$**
    **24**
    
    **$**
    **(27**
    **)**





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




Cash earnings (in
the table above) are not a measure of performance calculated in accordance with
GAAP. Penelec believes that cash earnings is a useful financial measure because
it provides investors and management with an additional means of evaluating its
cash-based operating performance.








**Reconciliation
      of Cash Earnings**
    
    **2005**
    
    **2004*****(In
      millions)***Net Income
      (GAAP)
    
    $
    21
    
    $
    6Non-Cash
      Charges (Credits):Provision for
      depreciation
    
    
    13
    
    
    11Amortization
      of regulatory assets
    
    
    13
    
    
    14Deferred costs
      recoverable as regulatory assets
    
    
    (19
    )
    
    (18
    )Deferred
      income taxes and investment tax credits
    
    
    2
    
    
    25Other non-cash
      expenses
    
    
    (2
    )
    
    5**Cash
      earnings (Non-GAAP)**
    
    **$**
    **28**
    
    **$**
    **43**








The $15 million
decrease in cash earnings is described above and under "Results of Operations".
This was partially offset by a $66 million change in working capital principally
due to changes in receivables, prepayments and accrued taxes, partially offset
by a change in the accounts payable.





*Cash Flows From
Financing Activities*




Net cash used for
financing activities was $7 million in the first quarter of 2005 compared to net
cash provided from financing activities of $89 million in the first quarter of
2004. The net change reflects the absence of 2004 long-term debt financing of
$150 million, a $60 million decrease in debt redemptions and $5 million of
common stock dividend payments to FirstEnergy in the first quarter of 2005.





121


Penelec had
approximately $10 million of cash and temporary investments (which include
short-term notes receivable from associated companies) and approximately $240
million of short-term indebtedness as of March 31, 2005. Penelec has
authorization from the SEC to incur short-term debt of up to $250 million
(including the utility money pool). Penelec will not issue FMB other than as
collateral for senior notes, since its senior note indentures prohibit (subject
to certain exceptions) Penelec from issuing any debt which is senior to the
senior notes. As of March 31, 2005, Penelec did not have the ability to
issue additional senior notes based upon FMB collateral. Penelec has no
restrictions on the issuance of preferred stock.





In addition, Penelec
has a $75 million customer receivables financing facility that was drawn for $70
million as of March 31, 2005. The facility expires on June 30, 2005,
and is expected to be renewed.





Penelec has the
ability to borrow from its regulated affiliates and FirstEnergy to meet its
short-term working capital requirements. FESC administers this money pool and
tracks surplus funds of FirstEnergy and its regulated subsidiaries. Companies
receiving a loan under the money pool agreements must repay the principal,
together with accrued interest, within 364 days of borrowing the funds. The rate
of interest is the same for each company receiving a loan from the pool and is
based on the average cost of funds available through the pool. The average
interest rate for borrowings under these arrangements in the first quarter of
2005 was 2.66%.





Penelec’s access to
capital markets and costs of financing are dependent on the ratings of its
securities and that of FirstEnergy. The ratings outlook on all securities is
stable.





On March 18,
2005, S&P stated that FirstEnergy’s Sammis NSR settlement was a very
favorable step for FirstEnergy, although it would not immediately affect
FirstEnergy’s ratings or outlook. S&P noted that it continues to monitor the
refueling outage at the Perry nuclear plant, which includes a detailed
inspection by the NRC, and that if FirstEnergy should exit the outage
without significant negative findings or delays the ratings outlook would be
revised to positive.





*Cash Flows From
Investing Activities*




Cash used for
investing activities was $17 million in the first quarter of 2005 compared to
$62 million in the first quarter of 2004. The decrease was primarily due to the
absence in 2005 of a $51 million repayment to the NUG trust fund in 2004,
partially offset by increased loans of $3 million to associated companies. In
both periods, cash outflows for property additions were made to support the
distribution of electricity.





During the remaining
quarters of 2005, capital requirements for property additions are expected to be
about $73 million. Penelec has additional requirements of approximately $11
million for maturing long-term debt during the remainder of 2005. Those
requirements are expected to be satisfied from internal cash and short-term
credit arrangements.





Penelec’s capital
spending for the period 2005-2007 is expected to be about $272 million for
property additions and improvements, of which about $89 million applies to 2005.





**Market Risk
Information**




Penelec uses various
market risk sensitive instruments, including derivative contracts, primarily to
manage the risk of price and interest rate fluctuations. FirstEnergy’s Risk
Policy Committee, comprised of members of senior management, provides general
management oversight to risk management activities throughout the
Company.





*Commodity Price
Risk*





Penelec is exposed
to market risk primarily due to fluctuations in electricity and natural gas
prices. To manage the volatility relating to these exposures, it uses a variety
of non-derivative and derivative instruments, including options and futures
contracts. The derivatives are used for hedging purposes. Penelec’s non-hedge
derivative contracts represent non-trading positions that do not qualify for
hedge treatment under SFAS 133. As of March 31, 2005, Penelec’s commodity
derivatives contract was an embedded option with a fair value of $14 million. A
decrease of $1 million in the value of this asset was recorded as a decrease in
a regulatory liability and, therefore, had no impact on net income.





The valuation of
derivative contracts is based on observable market information to the extent
that such information is available. In cases where such information is not
available, Penelec relies on model-based information. The model provides
estimates of future regional prices for electricity and an estimate of related
price volatility. Penelec uses these results to develop estimates of fair value
for financial reporting purposes and for internal management decision making.
The valuation of the derivative contract at March 31, 2005 uses prices from
sources shown in the following table:





122








**Source
      of Information****—Fair
      Value by Contract Year**
    
    **2005**
    
    **2006**
    
    **2007**
    
    **2008**
    
    **2009**
    
    **Thereafter**
    
    **Total*****(In
      millions)***Prices based
      on external sources(1)
    
    $
    3
    
    $
    3
    
    $
    --
    
    $
    --
    
    $
    --
    
    $
    --
    
    $
    6Prices based
      on models
    
    
    --
    
    
    --
    
    
    2
    
    
    2
    
    
    2
    
    
    2
    
    
    8Total
    
    $
    3
    
    $
    3
    
    $
    2
    
    $
    2
    
    $
    2
    
    $
    2
    
    $
    14





(1)  Broker quote
sheets.




Penelec performs
sensitivity analyses to estimate its exposure to the market risk of its
commodity positions. A hypothetical 10% adverse shift (an increase or decrease
depending on the derivative position) in quoted market prices in the near term
on both its trading and nontrading derivative instruments would not have had a
material effect on its consolidated financial position or cash flows as of
March 31, 2005.





*Equity Price
Risk*




Included in nuclear
decommissioning trusts are marketable equity securities carried at their current
fair value of approximately $58 million and $60 million as of March 31,
2005 and December 31, 2004, respectively. A hypothetical 10% decrease in
prices quoted by stock exchanges would result in a $6 million reduction in fair
value as of March 31, 2005.





**Outlook** ****





The electric industry continues to transition to a more competitive environment
and all of Penelec's customers can select alternative energy suppliers. Penelec
continues to deliver power to residential homes and businesses through its
existing distribution system, which remains regulated. Customer rates have been
restructured into separate components to support customer choice. Penelec has 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*





Beginning in 1999,
all of Penelec's customers had a choice for electric generation suppliers.
Penelec's customer rates were restructured to itemize (unbundle) the current
price of electricity into its component elements - including generation,
transmission, distribution and stranded cost recovery. In the event customers
obtain power from an alternative source, the generation portion of Penelec's
rates is excluded from their bill and the customers receive a generation charge
from the alternative supplier.





Regulatory assets
are costs which have been authorized by the PPUC and the FERC for recovery from
customers in future periods and, without such authorization, would have been
charged to income when incurred. Penelec's regulatory assets as of
March 31, 2005 and December 31, 2004 were $278 million and $200 million,
respectively.





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





On January 12,
2005, Penelec filed a request with the PPUC for deferral of transmission-related
costs beginning January 1, 2005, estimated to be approximately $4 million
per month.





See Note 13 to the
consolidated financial statements for further details and a complete discussion
of regulatory matters in Pennsylvania, including a more detailed discussion of
reliability initiatives, including actions by the PPUC that impact
Penelec.





123





*Environmental
Matters*





Penelec accrues
environmental liabilities only when it concludes that it is probable that it has
an obligation for such costs and can reasonably determine the amount of such
costs. Unasserted claims are reflected in Penelec's determination of
environmental liabilities and are accrued in the period that they are both
probable and reasonably estimable.





Penelec has been
named a PRP at waste disposal sites, which may require cleanup under the
Comprehensive Environmental Response, Compensation and Liability Act of 1980.
Allegations of disposal of hazardous substances at historical sites and the
liability involved are often unsubstantiated and subject to dispute; however,
federal law provides that all PRPs for a particular site are liable on a joint
and several basis.





*Other Legal
Proceedings*





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





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. The U.S. - Canada Power System Outage Task Force’s
final report in April 2004 on the outages 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 contained 46
"recommendations to prevent or minimize the scope of future blackouts."
Forty-five of those recommendations related to broad industry or policy matters
while one, including subparts, related to activities the Task Force recommended
be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the
causes of the August 14, 2003 power outages. FirstEnergy implemented
several initiatives, both prior to and since the August 14, 2003 power
outages, which were independently verified by NERC as complete in 2004 and were
consistent with these and other recommendations and collectively enhance the
reliability of its electric system. 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 completed in 2004 had a material effect on its
continuing 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 March 31, 2005 for any expenditures in excess
of those actually incurred through that date.





One complaint was
filed on August 25, 2004 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.





124





**New
Accounting Standards and Interpretations**





*FIN 47, “Accounting for Conditional Asset Retirement
Obligations - an interpretation of FASB Statement No. 143”*





On March 30,
2005, the FASB issued this interpretation to clarify the scope and timing of
liability recognition for conditional asset retirement obligations. Under this
interpretation, companies are required to recognize a liability for the fair
value of an asset retirement obligation that is conditional on a future event,
if the fair value of the liability can be reasonably estimated. In instances
where there is insufficient information to estimate the liability, the
obligation is to be recognized in the first period in which sufficient
information becomes available to estimate its fair value. If the fair value
cannot be reasonably estimated, that fact and the reasons why must be disclosed.
This interpretation is effective no later than the end of fiscal years ending
after December 15, 2005. FirstEnergy is currently evaluating the effect
this standard will have 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, FirstEnergy will continue
to evaluate its investments as required by existing authoritative
guidance.





125








**ITEM 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK**





See “Management’s Discussion and Analysis of Results
of Operation and Financial Condition - Market Risk Information” in Item 2 above.








**ITEM 4.
CONTROLS AND PROCEDURES**





**(a)**  **EVALUATION
OF DISCLOSURE CONTROLS AND PROCEDURES**




The applicable
registrant's chief executive officer and chief financial officer have reviewed
and evaluated the registrant's disclosure controls and procedures, as defined in
the Securities Exchange Act of 1934 Rules 13a-15(e) and 15d-15(e), as of the end
of the date covered by this report. Based on that evaluation, those officers
have concluded that the registrant's disclosure controls and procedures are
effective and were designed to bring to their attention material information
relating to the registrant and its consolidated subsidiaries by others within
those entities.





**(b)**  **CHANGES IN
INTERNAL CONTROLS**




During the quarter
ended March 31, 2005, there were no changes in the registrants' internal
control over financial reporting that have materially affected, or are
reasonably likely to materially affect, the registrants' internal control over
financial reporting.











126





***PART
II. OTHER INFORMATION***





**ITEM
1.**  **LEGAL
PROCEEDINGS**




Information required
for Part II, Item 1 is incorporated by reference to the discussions in Notes 12
and 13 of the Consolidated Financial Statements in Part I, Item 1 of this Form
10-Q.







**ITEM
2.**  **CHANGES IN
SECURITIES, USE OF PROCEEDS AND ISSUER PURCHASES OF EQUITY
SECURITIES**





**(e)**  **FirstEnergy**





The table below
includes information on a monthly basis regarding purchases made by FirstEnergy
of its common stock.


**Maximum
      Number****(or
      Approximate****Total
      Number of**
    
    **Dollar
      Value) of****Shares
      Purchased**
    
    **Shares
      that May****Total
      Number**
    
    
    
    **As
      Part of Publicly**
    
    **Yet Be
      Purchased****of
      Shares**
    
    **Average
      Price**
    
    **Announced
      Plans**
    
    **Under
      the Plans****Period**
    
    **Purchased
      (a)**
    
    **Paid
      per Share**
    
    **or
      Programs (b)**
    
    **or
      Programs**January 1-31,
      2005
    
    
    62,712
    
    $
    39.23
    
    
    --
    
    
    --February 1-28,
      2005
    
    
    104,824
    
    $
    40.78
    
    
    --
    
    
    --March 1-31,
      2005
    
    
    942,459
    
    $
    41.59
    
    
    --
    
    
    --First Quarter
      2005
    
    
    1,109,995
    
    $
    41.38
    
    
    --
    
    
    --







(a)  Share amounts
reflect purchases on the open market to satisfy FirstEnergy's obligations to
deliver common stock under its Executive and Director Incentive Compensation
Plan, Deferred Compensation Plan for Outside Directors, Executive Deferred
Compensation Plan, Savings Plan and Stock Investment Plan. In addition, such
amounts reflect shares tendered by employees to pay the exercise price or
withholding taxes upon exercise of stock options granted under the Executive and
Director Incentive Compensation Plan.





(b)
    FirstEnergy
      does not currently have any publicly announced plan or program for share
      purchases.





**ITEM
6.**  **EXHIBITS**





**(a)**  **Exhibits**





**Exhibit****Number****Met-Ed**12
    Fixed charge
      ratios31.1
    Certification
      of chief executive officer, as adopted pursuant to Rule
      13a-15(e)/15d-(e).31.2
    Certification
      of chief financial officer, as adopted pursuant to Rule
      13a-15(e)/15d-(e).32.1
    Certification
      of chief executive officer and chief financial officer, pursuant to 18
      U.S.C. Section 1350.**Penelec**10.1
    Term Loan Agreement, dated as of March 15, 2005, among
      Pennsylvania Electric Company, Union Bank of California,
      N.A., as Administrative Agent, Lead Arranger
      and Lender, and National City Bank as Arranger, Syndication Agent and
      Lender. (March 18, 2005 Form 8-K, Exhibit
      10.1).12
    Fixed charge
      ratios15
    Letter from
      independent registered public accounting firm31.1
    Certification
      of chief executive officer, as adopted pursuant to Rule
      13a-15(e)/15d-(e).31.2
    Certification
      of chief financial officer, as adopted pursuant to Rule
      13a-15(e)/15d-(e).32.1
    Certification
      of chief executive officer and chief financial officer, pursuant to 18
      U.S.C. Section 1350.**JCP&L**12
    Fixed charge
      ratios31.2
    Certification
      of chief financial officer, as adopted pursuant to Rule
      13a-15(e)/15d-(e).31.3
    Certification
      of chief executive officer, as adopted pursuant to Rule
      13a-15(e)/15d-(e).32.2
    Certification
      of chief executive officer and chief financial officer, pursuant to 18
      U.S.C. Section 1350.





127








**FirstEnergy**15
    Letter from
      independent registered public accounting firm31.1
    Certification
      of chief executive officer, as adopted pursuant to Rule
      13a-15(e)/15d-(e).31.2
    Certification
      of chief financial officer, as adopted pursuant to Rule
      13a-15(e)/15d-(e).32.1
    Certification
      of chief executive officer and chief financial officer, pursuant to 18
      U.S.C. Section 1350.**OE and
      Penn**15
    Letter from
      independent registered public accounting firm31.1
    Certification
      of chief executive officer, as adopted pursuant to Rule
      13a-15(e)/15d-(e).31.2
    Certification
      of chief financial officer, as adopted pursuant to Rule
      13a-15(e)/15d-(e).32.1
    Certification
      of chief executive officer and chief financial officer, pursuant to 18
      U.S.C. Section 1350.**CEI**31.1
    Certification
      of chief executive officer, as adopted pursuant to Rule
      13a-15(e)/15d-(e).31.2
    Certification
      of chief financial officer, as adopted pursuant to Rule
      13a-15(e)/15d-(e).32.1
    Certification
      of chief executive officer and chief financial officer, pursuant to 18
      U.S.C. Section 1350.**TE**31.1
    Certification
      of chief executive officer, as adopted pursuant to Rule
      13a-15(e)/15d-(e).31.2
    Certification
      of chief financial officer, as adopted pursuant to Rule
      13a-15(e)/15d-(e).32.1
    Certification
      of chief executive officer and chief financial officer, pursuant to 18
      U.S.C. Section 1350.





Pursuant to
reporting requirements of respective financings, JCP&L, Met-Ed and Penelec
are required to file fixed charge ratios as an exhibit to this Form 10-Q.
FirstEnergy, OE, CEI, TE and Penn do not have similar financing reporting
requirements and have not filed their respective fixed charge
ratios.





Pursuant to
paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, neither FirstEnergy, OE,
CEI, TE, Penn, JCP&L, Met-Ed nor Penelec have filed as an exhibit to this
Form 10-Q any instrument with respect to long-term debt if the respective
total amount of securities authorized thereunder does not exceed 10% of their
respective total assets of FirstEnergy and its subsidiaries on a consolidated
basis, or respectively, OE, CEI, TE, Penn, JCP&L, Met-Ed or Penelec but
hereby agree to furnish to the Commission on request any such
documents.








128











**SIGNATURE**











Pursuant to the
requirements of the Securities Exchange Act of 1934, each Registrant has duly
caused this report to be signed on its behalf by the undersigned thereunto duly
authorized.











May 5,
2005




















**FIRSTENERGY
      CORP.**Registrant**OHIO
      EDISON COMPANY**Registrant**THE
      CLEVELAND ELECTRIC****ILLUMINATING
      COMPANY**Registrant**THE
      TOLEDO EDISON COMPANY**Registrant**PENNSYLVANIA
      POWER COMPANY**Registrant**JERSEY
      CENTRAL POWER & LIGHT COMPANY**Registrant**METROPOLITAN
      EDISON COMPANY**Registrant**PENNSYLVANIA
      ELECTRIC COMPANY**Registrant














/s/       
      Harvey L.
       Wagner****
      Harvey L. WagnerVice President,
      Controller                                                 and
      Chief Accounting Officer








129