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, 2004

                                       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)
                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


<PAGE>

     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):

Yes (X) No (  )   FirstEnergy Corp.
Yes (  ) No (X )  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

     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 7, 2004
              -----                                            -----------------
   FirstEnergy Corp., $.10 par value                              329,836,276
   Ohio Edison Company, no par value                                      100
   The Cleveland Electric Illuminating Company, no par value       79,590,689
   The Toledo Edison Company, $5 par value                         39,133,887
   Pennsylvania Power Company, $30 par value                        6,290,000
   Jersey Central Power & Light Company, $10 par value             15,371,270
   Metropolitan Edison Company, no par value                          859,500
   Pennsylvania 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,
maintenance  costs being higher than  anticipated,  legislative  and  regulatory
changes (including revised  environmental  requirements),  adverse regulatory or
legal  decisions  and the  outcome  of  governmental  investigations  (including
revocation of necessary licenses or operating permits), 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  markets,
further  investigation  into the causes of the August 14, 2003,  regional  power
outage and the outcome,  cost and other effects of present and  potential  legal
and administrative proceedings and claims related to that outage, a denial of or
material change to FirstEnergy's  Application  related to its Rate Stabilization
Plan,  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,  2003 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.

<PAGE>


                                TABLE OF CONTENTS



                                                                          Pages
           Glossary of Terms.........................................     i - ii

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................     1-19


        FirstEnergy Corp.


           Consolidated Statements of Income.........................      20
           Consolidated Balance Sheets...............................      21
           Consolidated Statements of Cash Flows.....................      22
           Report of Independent Accountants.........................      23
           Management's Discussion and Analysis of Results
             of Operations and Financial Condition...................     24-48


        Ohio Edison Company


           Consolidated Statements of Income.........................      49
           Consolidated Balance Sheets...............................      50
           Consolidated Statements of Cash Flows.....................      51
           Report of Independent Accountants.........................      52
           Management's Discussion and Analysis of Results
             of Operations and Financial Condition...................     53-62


        The Cleveland Electric Illuminating Company


           Consolidated Statements of Income.........................      63
           Consolidated Balance Sheets...............................      64
           Consolidated Statements of Cash Flows.....................      65
           Report of Independent Accountants.........................      66
           Management's Discussion and Analysis of Results
             of Operations and Financial Condition...................     67-76


        The Toledo Edison Company


           Consolidated Statements of Income.........................      77
           Consolidated Balance Sheets...............................      78
           Consolidated Statements of Cash Flows.....................      79
           Report of Independent Accountants.........................      80
           Management's Discussion and Analysis of Results
             of Operations and Financial Condition...................     81-90


        Pennsylvania Power Company


           Consolidated Statements of Income.........................      91
           Consolidated Balance Sheets...............................      92
           Consolidated Statements of Cash Flows.....................      93
           Report of Independent Accountants.........................      94
           Management's Discussion and Analysis of Results
             of Operations and Financial Condition...................    95-101


<PAGE>


                           TABLE OF CONTENTS (Cont'd)


                                                                          Pages


        Jersey Central Power & Light Company

           Consolidated Statements of Income.........................      102
           Consolidated Balance Sheets...............................      103
           Consolidated Statements of Cash Flows.....................      104
           Report of Independent Accountants.........................      105
           Management's Discussion and Analysis of Results
             of Operations and Financial Condition...................    106-114


        Metropolitan Edison Company


           Consolidated Statements of Income.........................      115
           Consolidated Balance Sheets...............................      116
           Consolidated Statements of Cash Flows.....................      117
           Report of Independent Accountants.........................      118
           Management's Discussion and Analysis of Results
             of Operations and Financial Condition...................    119-127


        Pennsylvania Electric Company


           Consolidated Statements of Income.........................      128
           Consolidated Balance Sheets...............................      129
           Consolidated Statements of Cash Flows.....................      130
           Report of Independent Accountants.........................      131
           Management's Discussion and Analysis of Results
             of Operations and Financial Condition...................    132-141

        Item 3.   Quantitative and Qualitative Disclosure
                    About Market Risk................................      142

        Item 4.   Controls and Procedures............................      142


Part II      Other Information


        Item 1.   Legal Proceedings..................................      143

        Item 6.   Exhibits and Reports on Form 8-K...................      143


<PAGE>


GLOSSARY OF TERMS

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

ATSI.....................American Transmission Systems, Inc., owns and operates
                         transmission facilities
Avon.....................Avon Energy Partners Holdings
CEI......................The Cleveland Electric Illuminating Company, an Ohio
                         electric utility operating subsidiary
CFC......................Centerior Funding Corporation, a wholly owned finance
                         subsidiary of CEI
Emdersa................  Empresa Distribuidora Electrica Regional S.A
EUOC.....................Electric Utility Operating Companies, (OE, CEI, TE,
                         Penn, JCP&L, Met-Ed, Penelec, ATSI)
FENOC....................FirstEnergy Nuclear Operating Company, operates nuclear
                         generating facilities
FES......................FirstEnergy Solutions Corp., provides energy-related
                         products and services
FESC.....................FirstEnergy Service Company, provides legal, financial,
                         and other corporate support services
FGCO.....................FirstEnergy Generation Corp., operates nonnuclear
                         generating facilities
FirstCom.................First Communications, LLC, provides local and long-
                         distance phone service
FirstEnergy..............FirstEnergy Corp., a registered public utility holding
                         company
FSG......................FirstEnergy Facilities Services Group, LLC, the parent
                         company of several heating, ventilation air
                         conditioning and energy management companies
GLEP.....................Great Lakes Energy Partners, LLC, an oil and natural
                         gas exploration and production venture
GPU......................GPU, Inc., former parent of Jersey Central Power &
                         Light Copany, Metropolitan Edison Company and
                         Pennsylvania Electric Company, which merged with
                         FirstEnergy on November 7, 2001
GPU Capital..............GPU Capital, Inc., owned and operated electric
                         distribution systems in foreign countries
GPU Power................GPU Power, Inc., owned and operated generation
                         facilities in foreign countries
GPUS.....................GPU Service Company, previously provided corporate
                         support services
JCP&L....................Jersey Central Power & Light Company, a New Jersey
                         electric utility operating subsidiary
JCP&L Transition.........JCP&L Transition Funding LLC, a Delaware limited
                         liability company and issuer of transition bonds
MARBEL...................MARBEL Energy Corporation, holds FirstEnergy's interest
                         in Great Lakes Energy Partners, LLC
Met-Ed...................Metropolitan Edison Company, a Pennsylvania electric
                         utility operating subsidiary
MYR......................MYR Group, Inc., a utility infrastructure construction
                         service company
NEO......................Northeast Ohio Natural Gas Corp., a MARBEL subsidiary
OE.......................Ohio Edison Company, an Ohio electric utility operating
                         subsidiary
OE Companies.............OE and Pennsylvania Power Company
Penelec..................Pennsylvania Electric Company, a Pennsylvania electric
                         utility operating subsidiary
Penn.....................Pennsylvania Power Company, a Pennsylvania electric
                         utility operating subsidiary
PNBV.....................PNBV Capital Trust, a special purpose entity created
                         by OE in 1996
Shippingport.............Shippingport Capital Trust, a special purpose entity
                         created by CEI and TE in 1997


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

TE.......................The Toledo Edison Company, an Ohio electric utility
                         operating subsidiary
TECC.....................Toledo Edison Capital Corporation, a 90% owned
                         subsidiary of TE
ALJ......................Administrative Law Judge
AOCL.....................Accumulated Other Comprehensive Loss
APB......................Accounting Principles Board
APB 25...................APB No. 25, "Accounting for Stock Issued to Employees"
ARO......................Asset Retirement Obligation
BGS......................Basic Generation Service
CO2......................Carbon Dioxide
CTC......................Competitive Transition Charge
ECAR.....................East Central Area Reliability Agreement
EITF.....................Emerging Issues Task Force
EITF 03-6................EITF Issue No. 03-6, "Participating Securities and the
                         Two-Class Method Under Financial
                         Accounting Standards Board Statement No. 128, Earnings
                         per Share"
EITF 99-19...............EITF Issue No. 99-19, "Reporting Revenue Gross as a
                         Principal versus Net as an Agent"
EPA......................Environmental Protection Agency
FASB.....................Financial Accounting Standards Board
FASB Concepts No. 7......FASB Concepts Statement No. 7, "Using Cash Flow
                         Information and Present Value in
                         Accounting Measurements"
FERC.....................Federal Energy Regulatory Commission
FIN .....................FASB Interpretation
FIN 46R..................FIN 46 (revised December 2003), "Consolidation of
                         Variable Interest Entities"
FSP......................FASB Staff Position

                                       i


<PAGE>


FSP 106-1................FASB Staff Position 106-1, "Accounting and Disclosure
                         Requirements Related to the Medicare"
                         Prescription Drug, Improvement and Modernization Act
                         of 2003"
GAAP.....................Accounting Principles Generally Accepted in the
                         United States
IRS......................Internal Revenue Service
ISO......................Independent System Operator
KWH......................Kilowatt-hours
LOC......................Letter of Credit
Medicare Act.............Medicare Prescription Drug, Improvement and
                         Modernization Act of 2003
MISO.....................Midwest Independent System Operator, Inc.
Moody's..................Moody's Investors Service
MTC......................Market Transition Charge
MW.......................Megawatts
NAAQS....................National Ambient Air Quality Standards
NERC.....................North American Electric Reliability Council
NJBPU....................New Jersey Board of Public Utilities
NOX......................Nitrogen Oxides
NRC......................Nuclear Regulatory Commission
NUG......................Non-Utility Generation
OCI......................Other Comprehensive Income
OPEB.....................Other Post-Employment Benefits

PJM......................PJM Interconnection ISO
PLR......................Provider of Last Resort
PPUC.....................Pennsylvania Public Utility Commission
PRP......................Potentially Responsible Party
PUCO.....................Public Utilities Commission of Ohio
S&P......................Standard & Poor's
SBC......................Societal Benefits Charge
SEC......................Securities and Exchange Commission
SFAS.....................Statement of Financial Accounting Standards
SFAS 71..................SFAS No. 71, "Accounting for the Effects of Certain
                         Types of Regulation"
SFAS 87..................SFAS No. 87, "Employers' Accounting for Pensions"
SFAS 106.................SFAS No. 106, "Employers' Accounting for Postretirement
                         Benefits Other Than Pensions"
SFAS 123.................SFAS No. 123, "Accounting for Stock-Based Compensation"
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 and Extinguishment of Liabilities"
SFAS 142.................SFAS No. 142, "Goodwill and Other Intangible Assets"
SFAS 143.................SFAS No. 143, "Accounting for Asset Retirement
                         Obligations"
SFAS 144.................SFAS No. 144, "Accounting for the Impairment or
                         Disposal of Long-Lived Assets"
SFAS 150.................SFAS No. 150, "Accounting for Certain Financial
                         Instruments with Characteristics of both
                         Liabilities and Equity"
SO2......................Sulfur Dioxide
SPE......................Special Purpose Entity
TBC......................Transition Bond Charge
TEBSA....................Termobarranquilla S.A., Empresa de Servicios Publicos
TMI-2....................Three Mile Island Unit 2
VIE......................Variable Interest Entity

                                       ii

<PAGE>


 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:

          The  principal  business of  FirstEnergy  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.   These  utility   subsidiaries  are  referred  to  throughout  as
"Companies." Penn is a wholly owned subsidiary of OE. JCP&L,  Met-Ed and Penelec
were acquired in a merger  (which was effective  November 7, 2001) with GPU, the
former parent company of JCP&L, Met-Ed and Penelec. The merger was accounted for
by the purchase  method of accounting and the applicable  effects were reflected
on the financial  statements of JCP&L, Met-Ed and Penelec as of the merger date.
FirstEnergy's consolidated financial statements also include its other principal
subsidiaries:  FENOC,  FES and its subsidiary  FGCO,  FESC,  FirstCom,  FSG, GPU
Capital, GPU Power, MARBEL and MYR.

          The Companies follow the accounting policies and practices  prescribed
by the SEC, PUCO,  PPUC,  NJBPU and FERC. The condensed  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 prior year
amounts have been reclassified to conform with the current year presentation. In
particular,  expenses  (including  transmission  and  congestion  charges)  were
reclassified  among purchased power,  other operating costs and depreciation and
amortization  to  conform  with the  current  year  presentation  of  generation
commodity  costs. In addition,  revenues,  expenses and taxes related to certain
divestitures  in 2003 have been  reclassified  and reported net in  discontinued
operations (see Note 2).

          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, 2003 for FirstEnergy and the Companies.  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 those  estimates.  The reported
results of operations are not indicative of results of operations for any future
period.

          FirstEnergy's   and  the  Companies'   independent   accountants  have
performed  reviews  of,  and  issued  reports  on,  these  consolidated  interim
financial  statements in accordance  with standards  established by the American
Institute of  Certified  Public  Accountants.  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
accountant's liability under Section 11 does not extend to them.


2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

       Consolidation

          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 and VIE's for which FirstEnergy
or any of its subsidiaries is the primary beneficiary. 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 on the equity basis.

                                       1

<PAGE>

          FIN 46R addresses the consolidation of VIEs,  including SPEs, that are
not controlled  through voting interests or in which the equity investors do not
bear the residual economic risks and rewards. The first step under FIN 46R is to
determine whether an entity is within the scope of FIN 46R which occurs if it is
deemed to be a VIE. FirstEnergy and its subsidiaries  consolidate those VIEs for
which they have determined  that they are the primary  beneficiary as defined by
FIN 46R. The provisions of FIN 46R were effective  immediately for  transactions
entered into  subsequent to January 31, 2003 and became  effective no later than
December  31,  2003 for  entities  that  were  considered  SPEs  under  previous
guidance,  and no later than March 31, 2004 for all other entities. See Variable
Interest Entities below.

       Variable Interest Entities

          Included in FirstEnergy's  consolidated  financial statements are PNBV
and Shippingport,  two VIEs created in 1996 and 1997, respectively, to refinance
debt 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  with OE's  1987 sale and  leaseback  transactions  involving  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.  Consolidation of PNBV by FirstEnergy and OE as of December 31, 2003 changed
the trust  investment of $361 million to an investment in  collateralized  lease
bonds  of $372  million.  The $11  million  increase  represented  the  minority
interest in the total assets of PNBV.

          Shippingport  was established to purchase all of the lease  obligation
bonds  issued by the owner trusts in CEI's and TE's Bruce  Mansfield  Plant sale
and leaseback  transaction  in 1987. CEI and TE acquired all of the notes issued
by  Shippingport.  Consolidation  of this entity had no impact on the  financial
statements  of  FirstEnergy.  Prior to the  adoption of FIN 46R,  the assets and
liabilities  of  Shippingport  were  included  on a  proportionate  basis in the
financial  statements  of CEI  and  TE.  Adoption  of FIN  46R  resulted  in the
consolidation  of  Shippingport  by CEI as of December 31, 2003.  Shippingport's
note payable to TE of $199  million  ($10 million  current) and $208 million ($9
million  current) as of March 31, 2004 and December 31, 2003,  respectively,  is
included in long-term debt on CEI's Consolidated Balance Sheets.

          Through its investment in PNBV, OE has, and through their  investments
in  Shippingport,  CEI and TE have,  variable  interests in certain owner trusts
that  acquired the interests in the Perry Plant and Beaver Valley Unit 2, in the
case  of OE,  and  the  Bruce  Mansfield  Plant,  in the  case  of CEI  and  TE.
FirstEnergy  concluded that OE, CEI and TE were not the primary beneficiaries of
the relevant owner trusts and were  therefore not required to consolidate  these
entities.  The leases are accounted for as operating  leases in accordance  with
GAAP.  The  combined  purchase  price of $3.1  billion for all of the  interests
acquired by the owner  trusts in 1987 was funded  with debt of $2.5  billion and
equity of $600 million.

          Each of 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 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 - leaseback
agreements,  OE, CEI and TE have net minimum  discounted  lease payments of $706
million, $109 million and $595 million, respectively,  that would not be payable
if the casualty  value  payments are made. As of March 31, 2004, CEI and TE have
recorded above-market lease obligations related to the Bruce Mansfield Plant and
Beaver  Valley Unit 2 totaling  $1.1  billion  (CEI - $774 million and TE - $311
million),  of which $85  million  (CEI - $60  million  and TE - $25  million) is
current.

          CEI formed a wholly owned  statutory  business trust to sell preferred
securities and invest the gross proceeds in 9%  subordinated  debentures of CEI.
The sole assets of the trust are the  subordinated  debentures with an aggregate
principal  amount  of  $103  million.   The  trust's  preferred  securities  are
redeemable  at 100% of their  principal  amount  at CEI's  option  beginning  in
December 2006. CEI has effectively  provided a full and unconditional  guarantee
of the trust's obligations under the preferred securities.

          Met-Ed  and  Penelec  each  formed   statutory   business  trusts  for
substantially  similar  transactions to those of CEI. However,  ownership of the
respective  Met-Ed and Penelec trusts is through  separate  wholly owned limited
partnerships.  The sole assets of each trust are the preferred securities of the
applicable  limited  partnership,  whose  sole  assets  are the  7.35% and 7.34%
subordinated  debentures  (aggregate  principal  amount of $103 million each) of
Met-Ed  and  Penelec,   respectively.   The  trust's  preferred  securities  are
redeemable at 100% of their principal amount at the option of Met-Ed and Penelec
beginning in May 2004 and September 2004, respectively. In each case, Met-Ed and
Penelec  have  effectively  provided  a  full  and  unconditional  guarantee  of
obligations under the trust's preferred  securities.  Met-Ed has provided notice
to  holders of the trust  preferred  securities  that it intends to redeem  such
securities in May 2004.

                                       2

<PAGE>

          Upon  adoption of FIN 46R,  the  limited  partnerships  and  statutory
business  trusts  discussed  above were no longer  consolidated on the financial
statements of  FirstEnergy  or, as  applicable,  CEI,  Met-Ed or Penelec.  As of
December  31,  2003 and  March 31,  2004,  subordinated  debentures  held by the
affiliated trusts were included in long-term debt of the applicable  company and
equity investments in the trusts were included in other investments.

          For the quarter  ended March 31, 2004,  FirstEnergy  evaluated,  among
other  entities,  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 an EUOC 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,
either JCP&L,  Met-Ed or Penelec do not 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.

          FirstEnergy has requested but not received the  information  necessary
to determine  whether these nine entities are VIEs or whether  JCP&L,  Met-Ed or
Penelec is the primary beneficiary. In most cases, the requested information was
deemed to be competitive and proprietary data. 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 2004 and
2003 were $51 million  (JCP&L - $28 million,  Met-Ed - $16 million and Penelec -
$7  million)  and $56  million  (JCP&L - $34  million,  Met-Ed - $15 million and
Penelec - $7 million), respectively. FirstEnergy is required to continue to make
exhaustive efforts to obtain the necessary  information in future periods and is
unable to determine the possible impact of consolidating any such entity without
this information.

       Earnings Per Share

          Basic  earnings per share are computed  using the weighted  average of
actual common shares outstanding as the denominator.  Diluted earnings per share
reflect  the  weighted  average of actual  common  shares  outstanding  plus the
potential  additional common shares that could result if dilutive securities and
agreements were exercised in the  denominator.  In the first quarter of 2004 and
2003, stock-based awards to purchase shares of common stock totaling 3.3 million
and 3.6 million,  respectively,  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  and  Cumulative  Effect of  Accounting
Change:

                                                           Three Months Ended
                                                                March 31,
   Reconciliation of Basic and                            --------------------
   Diluted Earnings per Share                             2004            2003
   ---------------------------------------------------------------------------
                                                             (In thousands)
   Income before discontinued operations and
     cumulative effect of accounting change............  $173,999      $114,380

   Average Shares of Common Stock Outstanding:
     Denominator for basic earnings per share
      (weighted average shares actually outstanding)...   327,057       293,886
     Assumed exercise of dilutive stock options
      and awards.......................................     1,977           991

   Denominator for diluted earnings per share..........   329,034       294,877
   ===========================================================================

   Income before Discontinued Operations and Cumulative
   Effect of Accounting Change, per common share:
     Basic.............................................     $0.53         $0.39
     Diluted...........................................     $0.53         $0.39
   ---------------------------------------------------------------------------


       Preferred Stock Subject to Mandatory Redemption

          Long-term   debt   includes  the  preferred   stock  of   consolidated
subsidiaries  subject to mandatory  redemption as of March 31, 2004 and December
31,  2003 in  accordance  with  SFAS  150.  This  standard,  issued in May 2003,
establishes  standards  for  how  an  issuer  classifies  and  measures  certain
financial  instruments  with  characteristics  of both  liabilities  and equity;
certain  financial  instruments  that  embody  obligations  for the  issuer  are
required to be  classified  as  liabilities.  The adoption of SFAS 150 effective
July 1, 2003 had no impact on  FirstEnergy's  Consolidated  Statements of Income
because the preferred dividends were previously included in net interest charges
and required no  reclassification.  CEI and Penn,  however,  did not include the

                                       3

<PAGE>

preferred dividends on their manditorily  redeemable preferred stock in interest
expense for the quarter ended March 31, 2003, but have included the dividends in
interest charges for the quarter ended March 31, 2004.

       Securitized Transition Bonds

          The consolidated financial statements of FirstEnergy and JCP&L include
the financial  statements 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 each of  FirstEnergy's  and  JCP&L's
Consolidated Balance Sheets. The transition bonds represent  obligations only of
JCP&L Transition 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.

       Derivative Accounting

          FirstEnergy is exposed to financial risks  resulting from  fluctuating
interest  rates and commodity  prices,  including  electricity,  natural gas and
coal. To manage the volatility  relating to these exposures,  FirstEnergy 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 lesser extent, for trading purposes.
FirstEnergy's Risk Policy Committee,  comprised of executive officers, exercises
an independent risk oversight  function to ensure compliance with corporate risk
management policies and prudent risk management practices.

          FirstEnergy  uses  derivatives to hedge the risk of price and interest
rate fluctuations.  FirstEnergy's primary ongoing hedging activity involves cash
flow hedges of electricity  and natural gas purchases.  The maximum periods over
which the  variability of electricity  and natural gas cash flows are hedged are
two and three  years,  respectively.  Gains and losses from hedges of  commodity
price risks are included in net income when the  underlying  hedged  commodities
are  delivered.  Also,  the  ineffective  portion  of hedge  gains and losses is
included in net income.

          In  2001,   FirstEnergy   entered  into   interest   rate   derivative
transactions  to hedge a portion of the  anticipated  interest  payments on debt
related to the GPU  acquisition.  Gains and losses  from  hedges of  anticipated
interest  payments  on  acquisition  debt are  included  in net income  over the
periods that hedged interest  payments are made - 5, 10 and 30 years.  Gains and
losses from derivative  contracts are included in other operating expenses.  The
net  deferred  loss  included in AOCL as of March 31, 2004 and December 31, 2003
was $111 million.  Approximately $6 million (after tax) of the net deferred loss
on  derivative  instruments  in AOCL as of March 31,  2004,  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.

          During   the   first   quarter   of   2004,    FirstEnergy    executed
fixed-for-floating  interest  rate swap  agreements  with an aggregate  notional
amount of $200 million,  whereby FirstEnergy  receives fixed cash flows based on
the fixed coupons of the hedged securities and pays variable cash flows based on
short-term variable market interest rates. 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 received,
and  interest  payment  dates match those of the  underlying  debt  obligations.
FirstEnergy  entered into interest rate swap agreements on $200 million notional
amount of its  subsidiaries'  senior notes and subordinated  debentures having a
weighted average fixed interest rate of 5.73%; the interest rate swap agreements
have effectively converted that rate to a current weighted average variable rate
of 2.33%.  The notional  values of interest  rate swap  agreements  increased to
$1.35 billion as of March 31, 2004 from $1.15 billion as of December 31, 2003.

       Goodwill

          In a business  combination,  the excess of the purchase price over the
estimated fair values of assets acquired and  liabilities  assumed is recognized
as goodwill.  Based on the guidance provided by SFAS 142, FirstEnergy  evaluates

                                       4

<PAGE>

its goodwill for  impairment at least annually and would make such an evaluation
more frequently if indicators of impairment should arise. In accordance with the
accounting  standard,  if the fair  value of a  reporting  unit is less than its
carrying value (including goodwill),  the goodwill is tested for impairment.  If
an impairment is  indicated,  FirstEnergy  recognizes a loss - calculated as the
difference between the implied fair value of a reporting unit's goodwill and the
carrying value of the goodwill.

          As of March 31, 2004,  FirstEnergy  had $6.1 billion of goodwill  that
primarily  relates to its regulated  services  segment.  In the first quarter of
2004, FirstEnergy adjusted goodwill for interest received on a pre-merger income
tax refund  related to the former  GPU  companies.  A summary of the  changes in
FirstEnergy's goodwill for the three months ended March 31, 2004 is shown below:

                                                       (In millions)
              ------------------------------------------------------
              Balance as of December 31, 2003 ........     $6,128
              GPU acquisition.........................        (11)
                                                           ------

              Balance as of March 31, 2004............     $6,117
                                                           ======


       Comprehensive Income

          Comprehensive   income   includes   net  income  as  reported  on  the
Consolidated  Statements of Income and all other changes in common stockholders'
equity, except those resulting from transactions with common stockholders. As of
March 31, 2004, FirstEnergy's AOCL was approximately $344 million as compared to
the December 31, 2003 balance of $353 million. A reconciliation of net income to
comprehensive  income for the three  months  ended March 31,  2004 and 2003,  is
shown below:

                                                            Three Months Ended
                                                                   March 31,
                                                            -------------------
                                                            2004           2003
                                                            ----           ----
                                                               (In thousands)

     Net income.............................              $173,999      $218,502

     Other comprehensive income, net of tax:
       Change in fair value of hedge transactions             (393)        4,341
       Unrealized gains on available for sale securities     9,215         1,484
                                                          --------      --------

     Comprehensive income...................              $182,821      $224,327
                                                          ========      ========

     Asset Retirement Obligations

          FirstEnergy   recognizes  a  liability  for   retirement   obligations
associated  with  tangible  assets in  accordance  with SFAS 143. The  Companies
recognize a regulatory  asset or liability  when the criteria for such treatment
are met.  FirstEnergy  has identified  applicable  legal  obligations as defined
under the standard 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 was $1.198  billion as of March 31,
2004 and  included  $1.185  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 (as discussed in FASB Concepts No. 7) 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, 2004, the
fair value of the  decommissioning  trust assets was $1.420  billion.  Under the
current terms of the plants' operating licenses, payments for decommissioning of
the nuclear  generating  units would begin in 2014, when actual  decommissioning
work would begin.

          The  following  table  provides  the  beginning  and ending  aggregate
carrying amount of the total ARO and the changes to the balance during the first
quarter of 2004.


   ARO Reconciliation                                                 2004
   ----------------------------------------------------------------------------
                                                                   (In millions)
   Beginning balance as of January 1, 2004 ......................    $1,179
   Liabilities incurred..........................................        --
   Liabilities settled...........................................        --
   Accretion in 2004.............................................        19
   Revisions in estimated cash flows.............................        --
   ------------------------------------------------------------------------
   Ending balance as of March 31, 2004...........................    $1,198
   ------------------------------------------------------------------------

                                       5

<PAGE>

       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 March  2004,  the  FASB  issued  an  exposure  draft of a  proposed
standard that, if adopted, will change the accounting for employee stock options
and  other  equity-based  compensation.  The  proposed  standard  would  require
companies to expense the fair value of stock options on the grant date and would
be effective for the Companies on January 1, 2005. FirstEnergy will evaluate the
requirements  of the final  standard,  expected by late 2004,  to determine  the
impact on its results of operations.

          If FirstEnergy had accounted for employee stock options under the fair
value  method,  as  provided  under  SFAS 123,  a higher  value  would have been
assigned to the options  granted.  The effects of applying fair value accounting
to  FirstEnergy's  stock  options would be reductions to net income and earnings
per share. The following table summarizes those effects.

                                                       Three Months Ended
                                                              March 31,
                                                       ------------------
                                                        2004           2003
                                                        ----           ----
                                                          (In thousands)

         Net income, as reported...................   $173,999       $218,502

         Add back stock-based compensation
           expense reported in net income, net of tax
           (based on APB 25).......................         --             43

         Deduct stock-based compensation expense
           based upon estimated fair value, net of tax  (4,404)        (2,983)
         ---------------------------------------------------------------------

         Adjusted net income.......................   $169,595       $215,562
         ---------------------------------------------------------------------

         Earnings Per Share of Common Stock -
           Basic
              As Reported..........................      $0.53          $0.74
              Adjusted.............................      $0.52          $0.73
           Diluted
              As Reported..........................      $0.53          $0.74
              Adjusted.............................      $0.52          $0.73


       Discontinued Operations

          FirstEnergy's  discontinued  operations  in the first  quarter of 2003
consisted  of the net results  aggregating  $2 million  from its  Argentina  and
Bolivia  international  businesses and certain domestic  operations  divested in
2003.  The  related  revenues,  expenses  and taxes were  reclassified  from the
previously reported Consolidated Statement of Income for the quarter ended March
31,  2003 and netted in  Discontinued  Operations.  In April  2003,  FirstEnergy
divested  its  ownership  in Emdersa  through the  abandonment  of its shares in
Emdersa's  parent  company,  GPU Argentina  Holdings,  Inc. The  abandonment was
accomplished by relinquishing  FirstEnergy's  shares to the independent Board of
Directors of GPU Argentina  Holdings,  relieving  FirstEnergy  of all rights and
obligations relative to this business.  FirstEnergy sold its Bolivia operations,
Empresa  Guaracachi  S.A., in December 2003.  Domestic  operations  sold in 2003
consisted of three former FSG subsidiaries and the MARBEL subsidiary, NEO.

       Cumulative Effect of Accounting Change

          As a result of adopting  SFAS 143 in January  2003,  asset  retirement
costs were recorded in the amount of $602 million as part of the carrying amount
of the related  long-lived  asset,  offset by accumulated  depreciation  of $415
million. The ARO liability on the date of adoption was $1.11 billion,  including
accumulated accretion for the period from the date the liability was incurred to
the  date  of  adoption.   The  remaining   cumulative   effect  adjustment  for
unrecognized depreciation and accretion, offset by the reduction in the existing
decommissioning  liabilities and the reversal of accumulated  estimated  removal
costs for  non-regulated  generation  assets,  was a $175  million  increase  to
income,  $102  million net of tax, or $0.35 per share of common stock (basic and
diluted) in the quarter ended March 31, 2003.

                                       6

<PAGE>

       Restatements of TE and JCP&L Previously Reported Quarterly Results

          Earnings for the first  quarter of 2003 have been  restated for TE and
JCP&L to reflect  adjustments  to costs that were  subsequently  capitalized  to
construction projects. The results for TE have also been restated to correct the
amount reported for interest expense.  TE's costs which were originally recorded
as operating  expenses and were  subsequently  capitalized to construction  were
$0.4  million  ($0.2  million  after-tax)  in the first  quarter  of 2003.  TE's
interest expense was overstated by $0.9 million ($0.5 million  after-tax) in the
first quarter of 2003. Similar to TE, JCP&L's capital costs originally  recorded
as operating  expenses were $0.2 million  ($0.1 million  after-tax) in the first
quarter  of 2003.  The  impact  of these  adjustments  was not  material  to the
consolidated balance sheets or consolidated  statements of cash flows for TE and
JCP&L for any quarter of 2003.

          The effects of these  adjustments  on the  consolidated  statements of
income previously reported for TE and JCP&L for the three months ended March 31,
2003, are as follows:

<TABLE>
<CAPTION>
                                                          TE                                     JCP&L
                                            ----------------------------            ----------------------------
                                            As Previously         As                As Previously         As
                                               Reported         Restated              Reported          Restated
                                            -------------     -----------           -------------     ------------
                                                                        (In thousands)

<S>                                         <C>             <C>                      <C>              <C>
Operating Revenues..........................$   231,822     $    231,822             $  656,952       $   656,952
Operating Expenses..........................    226,345          226,501                581,744           581,609
                                            -----------     ------------             ----------       -----------
Operating Income............................      5,477            5,321                 75,208            75,343
Other income................................      3,100            3,100                  1,176             1,176
                                            -----------     ------------             ----------       -----------
Income before net interest charges..........      8,577            8,421                 76,384            76,519
Net interest charges........................      9,977            9,050                 22,502            22,502
                                            -----------     ------------             ----------       -----------
Income (loss) before cumulative effect
   of accounting change.....................    (1,400)            (629)                 53,882            54,017
Cumulative effect of accounting change......     25,550           25,550                     --                --
                                            -----------     ------------             ----------       -----------
Net income..................................     24,150           24,921                 53,882            54,017
Preferred stock dividend requirements.......      2,205            2,205                    125               125
                                            -----------     ------------             ----------       -----------
Earnings attributable to
   common stock.............................$    21,945     $     22,716             $   53,757       $    53,892
                                            ===========     ============             ==========       ===========
</TABLE>


3 - COMMITMENTS, GUARANTEES AND CONTINGENCIES:

       Capital Expenditures

          FirstEnergy's  current forecast reflects expenditures of approximately
$2.3 billion (OE-$295  million,  CEI-$275  million,  TE-$141 million,  Penn-$143
million, JCP&L-$446 million, Met-Ed-$168 million, Penelec-$198 million, ATSI-$66
million,  FES-$443  million and other  subsidiaries-$125  million)  for property
additions and improvements from 2004-2006,  of which  approximately $720 million
(OE-$111 million, CEI-$95 million, TE-$49 million, Penn-$63 million,  JCP&L-$150
million,  Met-Ed-$55 million,  Penelec-$65  million,  ATSI-$23 million,  FES-$71
million and other  subsidiaries-$38  million) is applicable to 2004. Investments
for  additional  nuclear fuel during the  2004-2006  period are  estimated to be
approximately  $315 million (OE-$45 million,  CEI-$62  million,  TE-$44 million,
Penn-$35  million and  FES-$129  million),  of which  approximately  $86 million
(OE-$26 million,  CEI-$27 million,  TE-$12 million and Penn-$21 million) applies
to 2004.

       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.  As of March 31, 2004,  outstanding  guarantees and
other assurances  aggregated $1.9 billion and included  contract  guarantees ($1
billion), surety bonds ($0.2 billion) and letters of credit ($.7 million).

          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 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 that such parental  guarantees of $1 billion  (included in the $1.9
billion discussed above) as of March 31, 2004 will increase amounts otherwise to
be paid by  FirstEnergy  to meet its  obligations  incurred in  connection  with
financings and ongoing energy and energy-related activities is remote.

                                       7
<PAGE>

          While  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  payment of cash
collateral  or  provision  of an  LOC  may  be  required.  The  following  table
summarizes collateral provisions as of March 31, 2004:

                                           Collateral Paid
                            Total      --------------------------     Remaining
Collateral Provisions      Exposure    Cash      Letters of Credit   Exposure(1)
--------------------------------------------------------------------------------
                                          (In millions)
Rating downgrade..........    $228     $133           $18              $  77
Adverse event.............     232       --            69                163
----------------------------------------------------------------------------
Total.....................    $460     $133           $87               $240
============================================================================


(1)  As of  April  12,  2004,  FirstEnergy's  remaining  exposure  was $237
     million,  with $141  million  of cash and $72  million  of  letters of
     credit provided as collateral.


          Most of FirstEnergy's  surety bonds are backed by various  indemnities
common  within the  insurance  industry.  Surety  bonds and related  FirstEnergy
guarantees of $240 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 also  guaranteed the  obligations of the operators of
the TEBSA  project  in  Colombia,  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 the
TEBSA  project  lenders a $60 million  letter of credit,  which is renewable and
declines yearly based upon the senior  outstanding debt of TEBSA. This letter of
credit granted  FirstEnergy  the ability to sell its remaining 20.1% interest in
Avon (parent of Midlands Electricity in the United Kingdom).

       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  material  compliance  with  existing
regulations  but is unable to predict  future change in regulatory  policies and
what,  if any,  the  effects  of such  change  would be.  FirstEnergy  estimates
additional  capital  expenditures for environmental  compliance of approximately
$91  million for 2004  through  2006,  which is included in the $2.3  billion of
forecasted  capital  expenditures  for 2004 through 2006.  Additional  estimated
capital  expenditures of $481 million  relating to proposed  environmental  laws
could be required after 2006.

         Clean Air Act Compliance

          The Companies are required to meet federally approved SO2 regulations.
Violations of such  regulations  can result in shutdown of the  generating  unit
involved  and/or  civil or criminal  penalties of up to $31,500 for each day the
unit  is in  violation.  The  EPA  has an  interim  enforcement  policy  for SO2
regulations  in Ohio that  allows  for  compliance  based on a 30-day  averaging
period.  The Companies cannot predict what action the EPA may take in the future
with respect to the interim enforcement policy.

          The Companies are complying with SO2 reduction  requirements under the
Clean Air Act Amendments of 1990 by burning  lower-sulfur fuel,  generating more
electricity from lower-emitting  plants,  and/or using emission allowances.  NOx
reductions required by the 1990 Amendments are being achieved through combustion
controls and the generation of more  electricity at  lower-emitting  plants.  In
September  1998,  the  EPA  finalized   regulations   requiring  additional  NOx
reductions from the Companies' facilities.  The EPA's NOx Transport Rule imposes
uniform  reductions of NOx emissions  (an  approximate  85% reduction in utility
plant NOx emissions from projected 2007  emissions)  across a region of nineteen
states (including Michigan,  New Jersey, Ohio and Pennsylvania) and the District
of Columbia  based on a  conclusion  that such NOx  emissions  are  contributing
significantly to ozone levels in the eastern United States. State Implementation
Plans (SIP) must comply by May 31, 2004 with individual  state NOx budgets.  New
Jersey and  Pennsylvania  submitted a SIP that required  compliance with the NOx
budgets at the Companies' New Jersey and Pennsylvania facilities by May 1, 2003.
Michigan and Ohio submitted a SIP that requires  compliance with the NOx budgets
at the Companies'  Michigan and Ohio  facilities by May 31, 2004. The Companies'
facilities have complied with the NOx budgets in 2003 and 2004, respectively.

                                       8

<PAGE>

         National Ambient Air Quality Standards

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

         Mercury Emissions

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

         W. H. Sammis Plant

          In 1999 and 2000,  the EPA  issued  Notices  of  Violation  (NOV) or a
Compliance Order to nine utilities covering 44 power plants, including the W. H.
Sammis Plant, which is owned by OE and Penn. In addition, the U.S. Department of
Justice filed eight civil complaints against various  investor-owned  utilities,
which  included a complaint  against OE and Penn in the U.S.  District Court for
the Southern  District of Ohio. The NOV and complaint  allege  violations of the
Clean Air Act based on  operation  and  maintenance  of the W. H.  Sammis  Plant
dating back to 1984.  The  complaint  requests  permanent  injunctive  relief to
require  the  installation  of "best  available  control  technology"  and civil
penalties of up to $27,500 per day of violation.  On August 7, 2003,  the United
States  District Court for the Southern  District of Ohio ruled that 11 projects
undertaken   at  the  W.  H.  Sammis  Plant   between  1984  and  1998  required
pre-construction  permits  under the Clean Air Act.  The  ruling  concludes  the
liability  phase of the case,  which deals with  applicability  of Prevention of
Significant  Deterioration  provisions  of the Clean Air Act. The remedy  phase,
which is currently scheduled to be ready for trial beginning July 19, 2004, will
address civil  penalties and what,  if any,  actions  should be taken to further
reduce  emissions  at the plant.  In the ruling,  the Court  indicated  that the
remedies  it  "may  consider  and  impose  involved  a much  broader,  equitable
analysis,  requiring the Court to consider air quality,  public health, economic
impact, and employment  consequences.  The Court may also consider the less than
consistent  efforts of the EPA to apply and further  enforce the Clean Air Act."
The potential penalties that may be imposed, as well as the capital expenditures
necessary to comply with  substantive  remedial  measures  that may be required,
could have a material  adverse impact on FirstEnergy's  financial  condition and
results of operations.  Management is unable to predict the ultimate  outcome of
this matter and no liability has been accrued as of March 31, 2004.

         Regulation of Hazardous Waste

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

          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 be held  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, 2004, based on estimates of the total

                                       9

<PAGE>

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
- $45.5 million, CEI - $2.4 million, TE - $0.2 million,  Met-Ed - $0.05 million,
Penelec - $0.02  million,  and other - $16.8  million) as of March 31, 2004. The
Companies accrue  environmental  liabilities only when they can 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.

         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
U.S. Senate required for  ratification.  However,  the Bush  administration  has
committed the United  States to a voluntary  climate  change  strategy to reduce
domestic  greenhouse gas intensity - the ratio of emissions to economic output -
by 18% through 2012.

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

         Clean Water Act

          Various  water  quality  regulations,  the  majority  of which are the
result  of the  federal  Clean  Water  Act  and  its  amendments,  apply  to the
Companies'  plants.  In addition,  Ohio, 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.

       Power Outages

          In July 1999, the Mid-Atlantic  states experienced a severe heat storm
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 New Jersey  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.

          Since July 1999, this litigation has involved a substantial  amount of
legal discovery including interrogatories,  request for production of documents,
preservation and inspection of evidence, and depositions of the named plaintiffs
and many JCP&L  employees.  In addition,  there have been many motions filed and
argued by the parties  involving  issues such as the  primary  jurisdiction  and
findings of the NJBPU, consumer fraud by JCP&L, strict product liability,  class
decertification, and the damages claimed by the plaintiffs. In January 2000, the
NJ Appellate  Division  determined that the trial court has proper  jurisdiction
over this  litigation.  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 products 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 have been appealed to the Appellation  Division and oral argument
is scheduled for May 2004. FirstEnergy is unable to predict the outcome of these
matters and no liability has been accrued as of March 31, 2004.

          On August  14,  2003,  various  states  and parts of  southern  Canada
experienced a widespread power outage.  That outage affected  approximately  1.4
million  customers in  FirstEnergy's  service area.  On April 5, 2004,  the U.S.
-Canada Power System Outage Task Force released its final report on this outage.
The final report supercedes the interim report that had been issued in November,
2003. In the final report,  the Task Force concluded,  among other things,  that
the problems  leading to the outage began in  FirstEnergy's  Ohio service  area.
Specifically,   the  final  report  concludes,  among  other  things,  that  the
initiation of the August 14th power outage resulted from the coincidence on that
afternoon of several events,  including,  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

                                       10

<PAGE>

effective 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 14th power outage and that it does not
adequately  address the  underlying  causes of the outage.  FirstEnergy  remains
convinced  that the outage  cannot be explained  by events on any one  utility's
system. The final report contains 46 "recommendations to prevent or minimize the
scope of future blackouts."  Forty-five of those recommendations relate to broad
industry  or policy  matters  while one  relates  to  activities  the Task Force
recommends be undertaken by FirstEnergy,  MISO,  PJM, and ECAR.  FirstEnergy has
undertaken  several  initiatives,  some prior to and some since the August  14th
power outage,  to enhance  reliability which are consistent with these and other
recommendations  and believes it will complete  those relating to summer 2004 by
June 30 (see Regulatory  Matters below).  As many of these  initiatives  already
were in process and  budgeted  in 2004,  FirstEnergy  does not believe  that any
incremental  expenses associated with additional  initiatives  undertaken during
2004 will  have a  material  effect  on its  operations  or  financial  results.
FirstEnergy  notes,   however,  that  the  applicable  government  agencies  and
reliability   coordinators   may  take  a  different   view  as  to  recommended
enhancements or may recommend  additional  enhancements in the future that could
require  additional,  material  expenditures.  FirstEnergy  has  not  accrued  a
liability as of March 31, 2004 for any  expenditures in excess of those actually
incurred through that date.

       Davis-Besse

          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
plant.  FirstEnergy is unable to predict the outcome of this  investigation.  In
addition,  FENOC remains subject to possible civil enforcement action by the NRC
in  connection  with the  events  leading  to the  Davis-Besse  outage  in 2002.
Further,  a  petition  was  filed  with  the NRC on  March  29,  2004 by a group
objecting to the NRC's restart order of the  Davis-Besse  Nuclear Power Station.
The Petition seeks among other things,  suspension of the Davis-Besse  operating
license.  If it were ultimately  determined that FirstEnergy has legal liability
or is  otherwise  made subject to  enforcement  action based on any of the above
matters with respect to the Davis-Besse outage, it could have a material adverse
effect on FirstEnergy's financial condition and results of operations.

       Other Legal Matters

          Various  lawsuits,  claims and  proceedings  related to  FirstEnergy's
normal business operations are pending against FirstEnergy and its subsidiaries.
The most significant not otherwise discussed above are described below.

          Legal  proceedings  have been filed against  FirstEnergy in connection
with,  among other things,  the  restatements in August 2003, by FirstEnergy and
its Ohio utility  subsidiaries of previously  reported results,  the August 14th
power outage described above, and the extended outage at the Davis-Besse Nuclear
Power  Station.  Depending  upon the  particular  proceeding,  the issues raised
include alleged  violations of federal  securities  laws,  breaches of fiduciary
duties under state law by FirstEnergy  directors and officers,  and damages as a
result  of one or more of the  noted  events.  The  securities  cases  have been
consolidated  into one  action  pending  in federal  court in Akron,  Ohio.  The
derivative  actions filed in federal court likewise have been  consolidated as a
separate  matter,  also in  federal  court in  Akron.  There  also  are  pending
derivative actions in state court.

          FirstEnergy's Ohio utility subsidiaries were also named as respondents
in two  regulatory  proceedings  initiated at the PUCO in response to complaints
alleging failure to provide  reasonable and adequate service stemming  primarily
from the August 14th power outage.  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
them.

          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  outage.  All three cases were
dismissed  for lack of  jurisdiction.  One case was  refiled at the PUCO and the
other two have been appealed.

          If FirstEnergy  were ultimately  determined to have legal liability in
connection with the legal proceedings  described above, it could have a material
adverse effect on its financial condition and results of operations.

                                       11

<PAGE>


4 - PENSION AND OTHER POSTRETIREMENT BENEFITS:

          The components of net periodic pension and postretirement benefit cost
consisted of the following:

<TABLE>

<CAPTION>
                                              Pension Benefits             Other Benefits
                                             --------------------       ------------------
                                             Three months ended         Three months ended
                                                    March 31,                  March 31,
                                             --------------------       ------------------
                                               2004          2003        2004        2003
------------------------------------------------------------------------------------------
                                                               (In millions)

<S>                                           <C>           <C>         <C>         <C>
Service cost .............................    $   19        $   17      $   10      $   11
Interest cost.............................        63            64          30          35
Expected return on plan assets............       (71)          (63)        (11)        (11)
Transition obligation.....................        --            --          --           2
Amortization of prior service cost........         2             2          (9)         (2)
Recognized net actuarial loss.............        10            16          10          11
                                              ------        ------      ------      ------
Net periodic cost.........................    $   23        $   36      $   30      $   46
                                              ======        ======      ======      ======
</TABLE>

          FirstEnergy  contributed  $16  million  to  its  other  postretirement
benefit plans in the first quarter of 2004 and has no funding  requirements  for
the  remainder of 2004.  FirstEnergy  did not  contribute  to its pension  plans
during  the  first  quarter  of 2004  and has no  funding  requirements  for the
remainder of 2004. The net periodic pension cost in the three months ended March
31, 2004 and March 31, 2003 included $3 million and $5 million, respectively, of
costs  capitalized.  Similarly,  the net periodic cost for other  postretirement
costs in the three  months  ended March 31, 2004 and March 31, 2003  included $4
million and $5 million, respectively, of capital costs.

          Pursuant to FSP 106-1  issued  January  12,  2004,  FirstEnergy  began
accounting for the effects of the Medicare Act effective January 1, 2004 because
of a plan  amendment  during the quarter,  which required  remeasurement  of the
plan's obligations.  Based on the guidance in proposed FSP 106-b issued in March
2004,  FirstEnergy has calculated a reduction of $318 million in the accumulated
postretirement  benefit  obligation as a result of the federal subsidy  provided
under the Medicare Act. The subsidy  reduced net periodic costs during the first
quarter of 2004 by $10 million,  which included  increased  amortization  of the
actuarial  experience  loss of $0.8  million,  reduction of $6.1 million in past
service cost,  $1.1 million of current  period  service cost and $3.6 million of
interest cost. Specific authoritative guidance on the accounting for the federal
subsidy  is  pending,  and when  issued,  could  require a change to  previously
reported  information.  In addition,  the plan amendment  announced in the first
quarter of 2004 reduced  postretirement benefit costs during the quarter by $9.2
million  as a  result  of  increased  cost-sharing  by  employees  and  retirees
effective January 1, 2005.


5 - INTERNATIONAL DIVESTITURES:

          FirstEnergy  completed the sale of its international assets during the
quarter  ended  March  31,  2004 with the sales of its  remaining  20.1  percent
interest in Avon on January 16, 2004, and its 28.67 percent interest in TEBSA on
January 30, 2004.  Impairment charges related to Avon and TEBSA were recorded in
the fourth quarter of 2003 and no gain or loss was recognized  upon the sales in
2004. Avon, TEBSA and other  international  assets sold in 2003 were acquired as
part of FirstEnergy's November 2001 merger with GPU.


6 - REGULATORY MATTERS:

          In Ohio,  New Jersey and  Pennsylvania,  laws  applicable  to electric
industry  deregulation  contain  similar  provisions  which are reflected in the
Companies' respective state regulatory plans:

          o   allowing the Companies'  electric  customers to select their
              generation suppliers;

          o   establishing  PLR obligations to customers in the Companies'
              service areas;

          o   allowing recovery of transition costs (sometimes referred to
              as stranded investment);

          o   itemizing  (unbundling)  the price of  electricity  into its
              component  elements -  including  generation,  transmission,
              distribution and transition costs recovery charges;

          o   deregulating the Companies' electric generation businesses;

          o   continuing  regulation of the  Companies'  transmission  and
              distribution system; and

          o   requiring corporate  separation of regulated and unregulated
              business activities.

                                       12

<PAGE>

       Reliability Initiatives

          On  October  15,  2003,  NERC  issued a Near  Term  Action  Plan  that
contained  recommendations  for all control areas and  reliability  coordinators
with  respect  to  enhancing  system   reliability.   Approximately  20  of  the
recommendations  were directed at the FirstEnergy  companies and broadly focused
on  initiatives  that are  recommended  for  completion  by summer  2004.  These
initiatives  principally  relate to  changes in voltage  criteria  and  reactive
resources  management;  operational  preparedness  and action  plans;  emergency
response   capabilities;   and,  preparedness  and  operating  center  training.
FirstEnergy   presented  a  detailed   compliance  plan  to  NERC,   which  NERC
subsequently  endorsed on May 7, 2004, and the various  initiatives are expected
to be completed no later than June 30, 2004.

          On  February  26  and  27,   2004,   certain   FirstEnergy   companies
participated  in a NERC Control Area  Readiness  Audit.  This audit,  part of an
announced  program by NERC to review control area operations  throughout much of
the United States during 2004, is an  independent  review to identify  areas for
improvement.  The final audit report was completed on April 30, 2004. The report
identified  positive  observations  and  included  various  recommendations  for
improvement.   FirstEnergy   is  currently   reviewing  the  audit  results  and
recommendations  and expects to implement  those relating to summer 2004 by June
30.  Based  on its  review  thus  far,  FirstEnergy  believes  that  none of the
recommendations  identify  a need for any  incremental  material  investment  or
upgrades to existing equipment.  FirstEnergy notes,  however, that NERC 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.

          On March 1, 2004, certain  FirstEnergy  companies filed, in accordance
with a November 25, 2003 order from the PUCO, their plan for addressing  certain
issues  identified  by the PUCO from the U.S. - Canada Power System  Outage Task
Force  interim  report.  In  particular,   the  filing  addressed   upgrades  to
FirstEnergy's  control room computer  hardware and software and  enhancements to
the  training of control  room  operators.  The PUCO will review the plan before
determining the next steps, if any, in the proceeding.

          On April 22,  2004,  FirstEnergy  filed  with FERC the  results of the
FERC-ordered independent study of part of Ohio's power grid. The study examined,
among other things,  the reliability of the transmission grid in critical points
in  the  Northern  Ohio  area  and  the  need,   if  any,  for  reactive   power
reinforcements  during summer 2004 and 2005.  FirstEnergy is currently reviewing
the  results  of that  study and  expects  to  complete  the  implementation  of
recommendations  relating to 2004 by this summer.  Based on its review thus far,
FirstEnergy  believes that the study does not recommend any incremental material
investment or 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.

          With respect to each of the  foregoing  initiatives,  FirstEnergy  has
requested and NERC has agreed to provide, a technical assistance team of experts
to provide ongoing guidance and assistance in implementing and confirming timely
and successful completion.

       Ohio

          In July 1999, Ohio's electric utility restructuring legislation, which
allowed Ohio electric customers to select their generation  suppliers  beginning
January 1, 2001,  was signed  into law.  Among  other  things,  the  legislation
provided for a 5% reduction on the generation portion of residential  customers'
bills and the  opportunity to recover  transition  costs,  including  regulatory
assets,  from  January 1, 2001 through  December  31, 2005  (market  development
period).  The period for the recovery of regulatory  assets only can be extended
up to  December  31,  2010.  The  recovery  period  extension  is related to the
customer shopping  incentives  recovery discussed below. The PUCO was authorized
to determine  the level of  transition  cost  recovery,  as well as the recovery
period for the  regulatory  assets portion of those costs,  in considering  each
Ohio electric utility's transition plan application.

          In July 2000, the PUCO approved FirstEnergy's  transition plan for OE,
CEI and TE (Ohio  Companies)  as modified by a settlement  agreement  with major
parties to the transition  plan. The  application of SFAS 71 to OE's  generation
business and the nonnuclear generation businesses of CEI and TE was discontinued
with the issuance of the PUCO transition plan order, as described further below.
Major provisions of the settlement  agreement  consisted of approval of recovery
of generation-related  transition costs as filed of $4.0 billion net of deferred
income  taxes  (OE-$1.6  billion,  CEI-$1.6  billion  and TE-$0.8  billion)  and
transition  costs related to  regulatory  assets as filed of $2.9 billion net of
deferred income taxes (OE-$1.0  billion,  CEI-$1.4 billion and TE-$0.5 billion),
with  recovery  through no later than 2006 for OE,  mid-2007 for TE and 2008 for
CEI,  except where a longer period of recovery is provided for in the settlement
agreement. The generation-related  transition costs include $1.4 billion, net of
deferred income taxes,  (OE-$1.0 billion,  CEI-$0.2 billion and TE-$0.2 billion)
of impaired  generating  assets  recognized  as  regulatory  assets as described
further below,  $2.4 billion,  net of deferred income taxes,  (OE-$1.2  billion,
CEI-$0.4  billion and TE-$0.8 billion) of above market operating lease costs and
$0.8  billion,  net of  deferred  income  taxes,  (CEI-$0.5  billion and TE-$0.3
billion)  of  additional  plant  costs  that  were  reflected  on CEI's and TE's
regulatory financial statements.

                                       13

<PAGE>

          Also as part of the settlement agreement,  FirstEnergy gives preferred
access over its subsidiaries to nonaffiliated marketers, brokers and aggregators
to 1,120 MW of generation  capacity through 2005 at established prices for sales
to the Ohio Companies' retail customers.  Customer prices are frozen through the
five-year market development period,  which runs through the end of 2005, except
for certain limited statutory exceptions, including the 5% reduction referred to
above. In February 2003, the Ohio Companies were authorized  increases in annual
revenues aggregating  approximately $50 million (OE-$41 million,  CEI-$4 million
and TE-$5  million) to recover  their higher tax costs  resulting  from the Ohio
deregulation legislation.

          FirstEnergy's Ohio customers choosing alternative suppliers receive an
additional  incentive applied to the shopping credit  (generation  component) of
45%  for  residential  customers,  30%  for  commercial  customers  and  15% for
industrial  customers.  The  amount of the  incentive  is  deferred  for  future
recovery  from  customers.  Subject to  approval by the PUCO,  recovery  will be
accomplished by extending the respective transition cost recovery period.


          On October 21, 2003, the Ohio EUOC filed an application  with the PUCO
to establish  generation service rates beginning January 1, 2006, in response to
expressed concerns by the PUCO about price and supply uncertainty  following the
end of the market development period. The filing included two options:

          o   A  competitive  auction,  which would  establish a price for
              generation that customers would be charged during the period
              covered by the auction, or

          o   A  Rate  Stabilization  Plan,  which  would  extend  current
              generation prices through 2008, ensuring adequate generation
              supply at stable  prices,  and  continuing  the Ohio  EUOC's
              support  of  energy  efficiency  and  economic   development
              efforts.

          Under  the first  option,  an  auction  would be  conducted  to secure
generation service for the Ohio EUOC's customers.  Beginning in 2006,  customers
would pay market prices for generation as determined by the auction.

          Under the Rate Stabilization  Plan option,  customers would have price
and supply  stability  through  2008 - three years  beyond the end of the market
development period - as well as the benefits of a competitive  market.  Customer
benefits would include:  customer  savings by extending the current five percent
discount on generation  costs and other customer  credits;  maintaining  current
distribution  base  rates  through  2007;  market-based  auctions  that  may  be
conducted  annually to ensure that  customers pay the lowest  available  prices;
extension  of the Ohio  EUOC's  support of  energy-efficiency  programs  and the
potential for continuing the program to give preferred  access to  nonaffiliated
entities to generation  capacity if shopping drops below 20%. Under the proposed
plan, the Ohio EUOC are requesting:

          o   Extension of the transition cost amortization  period for OE
              from 2006 to 2007;  for CEI from 2008 to mid-2009 and for TE
              from mid-2007 to mid-2008;

          o   Deferral  of  interest  costs  on the  accumulated  shopping
              incentives  and  other  cost  deferrals  as  new  regulatory
              assets; and

          o   Ability to initiate a request to increase  generation  rates
              under certain limited conditions.

          On January 7, 2004,  the PUCO staff filed  testimony  on the  proposed
rate plan  generally  supporting the Rate  Stabilization  Plan as opposed to the
competitive  auction proposal.  Hearings began on February 11, 2004. On February
23, 2004,  after  consideration  of PUCO Staff comments and testimony as well as
those  provided by some of the  intervening  parties,  FirstEnergy  made certain
modifications  to the Rate  Stabilization  Plan. Oral arguments were held before
the PUCO on April 21 and a decision is  expected  from the PUCO in the Spring of
2004.

       Transition Cost Amortization

          OE, CEI and TE amortize  transition  costs (see  Regulatory  Matters -
Ohio) using the effective interest method. Under the Ohio transition plan, total
transition  cost  amortization is expected to approximate the following for 2004
through  2009.

                                         (In millions)
               ---------------------------------------
               2004......................       $794
               2005......................        922
               2006......................        371
               2007......................        208
               2008......................        164
               2009......................         46
               ---------------------------------------

                                       14

<PAGE>

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

         New Jersey

          JCP&L's 2001 Final  Decision  and Order (Final  Order) with respect to
its rate  unbundling,  stranded cost and  restructuring  filings  confirmed rate
reductions  set  forth in its 1999  Summary  Order,  which had been in effect at
increasing  levels  through  July  2003.  The Final  Order  also  confirmed  the
establishment  of a  non-bypassable  SBC to recover costs which include  nuclear
plant  decommissioning  and  manufactured  gas plant  remediation,  as well as a
non-bypassable  MTC primarily to recover  stranded costs. The NJBPU has deferred
making a final  determination  of the net proceeds and stranded costs related to
prior  generating  asset  divestitures  until JCP&L's  request for an IRS ruling
regarding the treatment of associated federal income tax benefits is acted upon.
Should the IRS ruling support the return of the tax benefits to customers, there
would be no effect to  FirstEnergy's or JCP&L's net income since the contingency
existed prior to the merger and there would be an adjustment to goodwill.

          In addition,  the Final Order  provided for the ability to  securitize
stranded  costs  associated  with the divested  Oyster Creek Nuclear  Generating
Station.  Under NJBPU  authorization  in 2002,  JCP&L issued  through its wholly
owned subsidiary, JCP&L Transition, $320 million of transition bonds (recognized
on the Consolidated Balance Sheet) which securitized the recovery of these costs
and which provided for a usage-based  non-bypassable TBC and for the transfer of
the bondable transition property to another entity.

          Prior to August 1, 2003,  JCP&L's  PLR  obligation  to provide  BGS to
non-shopping  customers was supplied  almost  entirely from  contracted and open
market  purchases.  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, 2004, the  accumulated  deferred cost
balance totaled  approximately  $425 million,  after the charge discussed below.
The NJBPU also allowed  securitization of JCP&L's deferred balance to the extent
permitted by law upon application by JCP&L and a determination by the NJBPU that
the conditions of the New Jersey restructuring legislation are met. There can be
no  assurance  as to the  extent,  if any,  that  the  NJBPU  will  permit  such
securitization.

          Under New Jersey  transition  legislation,  all electric  distribution
companies  were  required to file rate cases to determine the level of unbundled
rate components to become effective August 1, 2003. JCP&L's two August 2002 rate
filings requested  increases in base electric rates of approximately $98 million
annually and  requested  the recovery of deferred  costs that  exceeded  amounts
being  recovered  under the current MTC and SBC rates;  one  proposed  method of
recovery of these costs is the  securitization  of the  deferred  balance.  This
securitization  methodology  is  similar  to  the  Oyster  Creek  securitization
discussed  above.  On July 25, 2003, the NJBPU announced its JCP&L base electric
rate proceeding decision, which reduced JCP&L's annual revenues by approximately
$62 million  effective  August 1, 2003.  The NJBPU decision also provided for an
interim  return on equity of 9.5% on JCP&L's rate base for six to twelve months.
During that period,  JCP&L will initiate another  proceeding to request recovery
of additional costs incurred to enhance system reliability.  In that proceeding,
the NJBPU could  increase the 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.  The net  revenue  decrease  from the
NJBPU's decision consists of a $223 million decrease in the electricity delivery
charge,  a $111 million  increase due to the August 1, 2003 expiration of annual
customer credits previously mandated by the New Jersey transition legislation, a
$49 million increase in the MTC tariff component,  and a net $1 million increase
in the SBC. The MTC allows for the  recovery of $465 million in deferred  energy
costs over the next ten years on an interim basis, thus disallowing $153 million
of the $618 million provided for in a preliminary  settlement  agreement between
certain parties. As a result,  JCP&L recorded charges to net income for the year
ended  December 31, 2003,  aggregating  $185 million  ($109  million net of tax)
consisting  of the $153 million of  disallowed  deferred  energy costs and other
regulatory assets.  JCP&L filed a motion for rehearing and reconsideration  with
the NJBPU on August 15,  2003 with  respect  to the  following  issues:  (1) the
disallowance of the $153 million  deferred energy costs; (2) the reduced rate of
return on equity;  and (3) $42.7 million of disallowed  costs to achieve  merger
savings.  On October 10, 2003,  the NJBPU held the motion in abeyance  until the
final  NJBPU  decision  and order  which is  expected to be issued in the second
quarter of 2004.

          JCP&L's BGS obligation for the twelve month period beginning August 1,
2003 was  auctioned  in February  2003.  The  auction  covered a fixed price bid
(applicable to all residential and smaller commercial and industrial  customers)
and an hourly price bid (applicable to all large industrial  customers) process.
JCP&L  sells  all  self-supplied  energy  (NUGs  and  owned  generation)  to the
wholesale market with offsetting  credits to its deferred energy  balances.  The
BGS auction for the subsequent  period was completed in February 2004. The NJBPU
adjusted the  generation  component of JCP&L's retail rates on August 1, 2003 to
reflect the results of the BGS auction.

          On April 28, 2004,  the NJBPU  directed JCP&L to file testimony by the
end of May 2004,  either  supporting  a  continuation  of the current  level and
duration of the funding of TMI-2 decommissioning costs by New Jersey ratepayers,
or, alternatively, proposing a reduction, termination or capping of the funding.
JCP&L cannot predict the outcome of this matter.

                                       15

<PAGE>

         Pennsylvania

          The PPUC authorized in 1998 rate restructuring  plans for Penn, Met-Ed
and Penelec. In 2000, the PPUC disallowed a portion of the requested  additional
stranded  costs above those amounts  granted in Met-Ed's and Penelec's 1998 rate
restructuring  plan orders.  The PPUC required Met-Ed and Penelec to seek an IRS
ruling  regarding the return of certain  unamortized  investment tax credits and
excess deferred income tax benefits to customers.  Similar to JCP&L's situation,
if the IRS ruling ultimately supports returning these tax benefits to customers,
there  would be no effect to  FirstEnergy's,  Met-Ed's or  Penelec's  net income
since the contingency  existed prior to the merger and would be an adjustment to
goodwill.

          In June 2001, the PPUC approved the Settlement Stipulation with all of
the major  parties in the  combined  merger and rate  relief  proceedings  which
approved  the  FirstEnergy/GPU  merger  and  provided  PLR  deferred  accounting
treatment for energy costs,  permitting  Met-Ed and Penelec to defer, for future
recovery, energy costs in excess of amounts reflected in their capped generation
rates retroactive to January 1, 2001. This PLR deferral accounting procedure was
later denied in a February 2002 Commonwealth Court of Pennsylvania decision. The
court decision also affirmed the PPUC decision regarding approval of the merger,
remanding  the  decision  to the PPUC only with  respect  to the issue of merger
savings. FirstEnergy established reserves in 2002 for Met-Ed's and Penelec's PLR
deferred energy costs which aggregated $287.1 million,  reflecting the potential
adverse impact of the then pending  Pennsylvania  Supreme Court decision whether
to review the Commonwealth Court decision. As a result,  FirstEnergy recorded in
2002 an aggregate non-cash charge of $55.8 million ($32.6 million net of tax) to
income for the deferred costs incurred subsequent to the merger. The reserve for
the  remaining  $231.3  million  of  deferred  costs  increased  goodwill  by an
aggregate net of tax amount of $135.3 million.

          On April 2,  2003,  the PPUC  remanded  the issue  relating  to merger
savings to the Office of  Administrative  Law for hearings,  directed Met-Ed and
Penelec to file a position paper on the effect of the  Commonwealth  Court order
on the Settlement Stipulation and allowed other parties to file responses to the
position paper. Met-Ed and Penelec filed a letter with the ALJ on June 11, 2003,
voiding the Settlement  Stipulation in its entirety and reinstating Met-Ed's and
Penelec's restructuring settlement previously approved by the PPUC.

          On October  2,  2003,  the PPUC  issued an order  concluding  that the
Commonwealth Court reversed the PPUC's June 20, 2001 order in its entirety.  The
PPUC directed Met-Ed and Penelec to file tariffs within thirty days of the order
to reflect the CTC rates and  shopping  credits that were in effect prior to the
June 21, 2001 order to be effective  upon one day's notice.  In response to that
order,  Met-Ed and Penelec  filed these  supplements  to their tariffs to become
effective October 24, 2003.

          On  October  8,  2003,   Met-Ed  and  Penelec  filed  a  petition  for
clarification  relating to the October 2, 2003 order on two issues: to establish
June 30, 2004 as the date to fully refund the NUG trust fund and to clarify that
the ordered  accounting  treatment  regarding the CTC rate/shopping  credit swap
should  follow the  ratemaking,  and that the PPUC's  findings  would not impair
their rights to recover all of their stranded costs. On October 9, 2003,  ARIPPA
(an  intervenor  in the  proceedings)  petitioned  the PPUC to direct Met-Ed and
Penelec  to  reinstate   accounting  for  the  CTC  rate/shopping   credit  swap
retroactive to January 1, 2002.  Several other parties also filed petitions.  On
October 16,  2003,  the PPUC issued a  reconsideration  order  granting the date
requested by Met-Ed and Penelec for the NUG trust fund refund,  denying Met-Ed's
and Penelec's other  clarification  requests and granting ARIPPA's petition with
respect to the  accounting  treatment  of the  changes to the CTC  rate/shopping
credit swap. On October 22, 2003, Met-Ed and Penelec filed an Objection with the
Commonwealth  Court  asking  that the Court  reverse  the  PPUC's  finding  that
requires  Met-Ed  and  Penelec  to treat the  stipulated  CTC rates that were in
effect from January 1, 2002 on a retroactive basis.

          On October  27,  2003,  a  Commonwealth  Court  judge  issued an Order
denying  Met-Ed's  and  Penelec's  objection  without  explanation.  Due  to the
vagueness  of the Order,  Met-Ed and  Penelec,  on October  31,  2003,  filed an
Application  for  Clarification  with the judge.  Concurrent  with this  filing,
Met-Ed and  Penelec,  in order to  preserve  their  rights,  also filed with the
Commonwealth  Court  both 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.  In addition to these findings,  Met-Ed and
Penelec,  in compliance  with the PPUC's  Orders,  filed revised PPUC  quarterly
reports for the twelve  months  ended  December  31, 2001 and 2002,  and for the
first two  quarters  of 2003,  reflecting  balances  consistent  with the PPUC's
findings in their Orders.

          Effective  September 1, 2002,  Met-Ed and Penelec agreed to purchase a
portion  of their PLR  requirements  from FES  through a  wholesale  power  sale
agreement.  The PLR sale  will be  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 assumed 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. FES has hedged most of Met-Ed's
and  Penelec's  unfilled  PLR on-peak  obligation  through 2004 and a portion of

                                       16

<PAGE>

2005, the period during which deferred  accounting was previously  allowed under
the PPUC's  order.  Met-Ed and Penelec  are  authorized  to  continue  deferring
differences between NUG contract costs and current market prices.

          In late 2003,  the PPUC  issued a  Tentative  Order  implementing  new
reliability  benchmarks  and  standards.  In  connection  therewith,   the  PPUC
commenced a  rulemaking  procedure  to amend the  Electric  Service  Reliability
Regulations to implement these new benchmarks,  and create additional  reporting
on  reliability.  Although  neither  the  Tentative  Order  nor the  Reliability
Rulemaking has been finalized,  the PPUC ordered all  Pennsylvania  utilities to
begin filing quarterly  reports on November 1, 2003. The comment period for both
the  Tentative  Order and the  Proposed  Rulemaking  Order has  closed.  Met-Ed,
Penelec and Penn are currently  awaiting the PPUC to issue a final order in both
matters.  The order  will  determine  (1) the  standards  and  benchmarks  to be
utilized, and (2) the details required in the quarterly and annual reports.

          On January 16,  2004,  the PPUC  initiated a formal  investigation  of
whether  Met-Ed's,   Penelec's  and  Penn's  "service  reliability   performance
deteriorated  to a point  below the level of service  reliability  that  existed
prior  to  restructuring"  in  Pennsylvania.  Discovery  has  commenced  in  the
proceeding  and Met-Ed's,  Penelec's  and Penn's  testimony is due May 14, 2004.
Hearings are scheduled to begin August 3, 2004 in this investigation and the ALJ
has been  directed to issue a  Recommended  Decision by September  30, 2004,  in
order  to  allow  the  PPUC  time to  issue a Final  Order  by year end of 2004.
FirstEnergy is unable to predict the outcome of the  investigation or the impact
of the PPUC order.


7 - NEW ACCOUNTING STANDARDS AND INTERPRETATIONS:

       EITF Issue No. 03-6,  "Participating  Securities and the Two-Class Method
       Under Financial  Accounting  Standards Board Statement No. 128,  Earnings
       per Share"

          On March 31, 2004, the FASB ratified the consensus reached by the EITF
on  Issue  03-6.  The  issue  addresses  a number  of  questions  regarding  the
computation of earnings per share by companies that have issued securities other
than  common  stock that  contractually  entitle  the holder to  participate  in
dividends and earnings of a company when,  and if, it declares  dividends on its
common stock. The issue also provides further guidance in applying the two-class
method of computing  earnings per share once it is determined that a security is
participating,  including  how to  allocate  undistributed  earnings  to  such a
security.  EITF 03-6 is effective for fiscal periods  beginning  after March 31,
2004. FirstEnergy is currently evaluating the effect of adopting EITF 03-6.

       FSP  106-1,  "Accounting  and  Disclosure  Requirements  Related  to  the
       Medicare Prescription Drug, Improvement and Modernization Act of 2003"

          Issued   January  12,  2004,   FSP  106-1   permits  a  sponsor  of  a
postretirement  health care plan that  provides a  prescription  drug benefit to
make a one-time  election to defer  accounting  for the effects of the  Medicare
Act.  FirstEnergy  elected to defer the effects of the  Medicare  Act due to the
lack of specific guidance.  Pursuant to FSP 106-1,  FirstEnergy began accounting
for the effects of the Medicare Act  effective  January 1, 2004 as a result of a
February  2, 2004 plan  amendment  that  required  remeasurement  of the  plan's
obligations.  See Note 2 for a discussion  of the effect of the federal  subsidy
and plan amendment on the consolidated financial statements.

       FIN 46 (revised  December  2003),  "Consolidation  of  Variable  Interest
       Entities"

          In  December  2003,  the  FASB  issued  a  revised  interpretation  of
Accounting  Research  Bulletin  No.  51,  "Consolidated  Financial  Statements",
referred  to as  FIN  46R,  which  requires  the  consolidation  of a VIE  by an
enterprise if that enterprise is determined to be the primary beneficiary of the
VIE. As required,  FirstEnergy  adopted FIN 46R for  interests in VIEs  commonly
referred to as special-purpose  entities effective December 31, 2003 and for all
other types of entities  effective  March 31, 2004.  Adoption of FIN 46R did not
have a material  impact on  FirstEnergy's  financial  statements for the quarter
ended March 31, 2004. See Note 2 for a discussion of variable interest entities.

          For the quarter  ended March 31, 2004,  FirstEnergy  evaluated,  among
other entities, its power purchase agreements and determined that it is possible
that  nine  NUG  entities  might  be  considered   variable  interest  entities.
FirstEnergy  has  requested  but  not  received  the  information  necessary  to
determine whether these entities are VIEs or whether JCP&L, Met-Ed or Penelec is
the primary beneficiary.  In most cases, the requested information was deemed to
be competitive  and  proprietary  data. 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 2004 and 2003 were
$51 million (JCP&L - $28 million, Met-Ed - $16 million and Penelec - $7 million)
and $56  million  (JCP&L - $34  million,  Met-Ed - $15  million and Penelec - $7
million),  respectively.  FirstEnergy is required to continue to make exhaustive

                                       17

<PAGE>

efforts to obtain the necessary  information  in future periods and is unable to
determine  the possible  impact of  consolidating  any such entity  without this
information.

       EITF Issue No. 03-11,  "Reporting Realized Gains and Losses on Derivative
       Instruments  That Are Subject to SFAS No. 133,  Accounting for Derivative
       Instruments and Hedging  Activities,  and Not "Held for Trading Purposes"
       as  Defined in EITF Issue  02-03,  "Issues  Involved  in  Accounting  for
       Derivative  Contracts Held for Trading Purposes and Contracts Involved in
       Energy Trading and Risk Management Activities."

       In July 2003,  the EITF  reached a  consensus  that  determining  whether
realized gains and losses on physically settled  derivative  contracts not "held
for trading  purposes"  should be reported in the income statement on a gross or
net  basis is a matter  of  judgment  that  depends  on the  relevant  facts and
circumstances.  The  consideration  of the  facts and  circumstances,  including
economic  substance,  should be made in the context of the various activities of
the entity  rather than based solely on the terms of the  individual  contracts.
The  adoption  of this  consensus  effective  January  1,  2004,  did not have a
material impact on the Companies' financial statements.


8 - SEGMENT INFORMATION:

          FirstEnergy operates under two reportable segments: regulated services
and competitive  services.  The aggregate  "Other"  segments do not individually
meet the criteria to be  considered a reportable  segment.  "Other"  consists of
interest expense related to holding company debt; corporate support services and
the international businesses acquired in the 2001 merger.  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 (OE,  CEI,  TE,  Penn,  JCP&L,
Met-Ed, Penelec and ATSI). The competitive services business segment consists of
the subsidiaries  (FES, FSG, MYR, MARBEL and FirstCom) that operate  unregulated
energy and  energy-related  businesses,  including  the  operation of generation
facilities  of OE,  CEI,  TE and Penn  resulting  from the  deregulation  of the
Companies' electric generation business (see Note 6 - Regulatory Matters).

          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 costs
recovery.

          The competitive  services segment has  responsibility  for FirstEnergy
generation  operations  as  discussed  under Note 6. As a result,  its  revenues
include  all  generation  electric  sales  revenues  (including  the  generation
services to regulated  franchise  customers  who have not chosen an  alternative
generation  supplier)  and all domestic  unregulated  energy and  energy-related
services  including  commodity  sales (both  electricity and natural gas) in the
retail and wholesale  markets,  marketing,  generation and sourcing of commodity
requirements,  providing local and long-distance phone service, as well as other
competitive energy-application services.

          Segment reporting in 2003 was reclassified to conform with the current
year  business  segment   organizations   and  operations.   Revenues  from  the
competitive  services  segment  now include all  generation  revenues  including
generation services to regulated  franchise customers  previously reported under
the  regulated  services  segment and now  exclude  revenues  from power  supply
agreements with the regulated services segments  previously reported as internal
revenues.  The regulated  services segment results now exclude  generation sales
revenues and related  generation  commodity  costs.  Certain amounts  (including
transmission and congestion  charges) were  reclassified  among purchased power,
other  operating  costs and  depreciation  and  amortization to conform with the
current year  presentation of generation  commodity costs. In addition,  segment
results have been adjusted to reflect the reclassification of revenue,  expense,
interest   expense  and  tax  amounts  of  divested   businesses   reflected  as
discontinued operations (see Note 2).

                                       18

<PAGE>

<TABLE>

<CAPTION>

         Segment Financial Information
         -----------------------------
                                         Regulated     Competitive                Reconciling
                                          Services       Services      Other      Adjustments    Consolidated
                                         ---------     -----------     -----      ------------   ------------
                                                                    (In millions)
Three Months Ended:

    March 31, 2004
    --------------
<S>                                     <C>           <C>             <C>        <C>               <C>
External revenues.....................  $  1,295      $   1,873       $    7     $    8(a)         $  3,183
Internal revenues.....................        --             --          120       (120)(b)              --
   Total revenues.....................     1,295          1,873          127       (112)              3,183
Depreciation and amortization.........       393              9           10         --                 412
Net interest charges..................       106             12           69        (15)(b)             172
Income taxes..........................       147             --          (31)        --                 116
Net income (loss).....................       216             --          (42)        --                 174
Total assets..........................    29,336          2,285          964         --              32,585
Total goodwill........................     5,981            136           --         --               6,117
Property additions....................        90             45            3         --                 138

    March 31, 2003
    --------------
External revenues.....................  $  1,309      $   1,874       $   34     $    4  (a)       $  3,221
Internal revenues.....................        --             --          124       (124) (b)             --
   Total revenues.....................     1,309          1,874          158       (120)              3,221
Depreciation and amortization.........       355             12            9         --                 376
Net interest charges..................       124             12          104        (34) (b)            206
Income taxes..........................       189            (66)         (29)        --                  94
Income before discontinued operations and
   cumulative effect of accounting change    257            (92)         (51)        --                 114
Net income (loss).....................       358            (96)         (44)        --                 218
Total assets..........................    30,417          2,449        1,421         --              34,287
Total goodwill........................     5,993            244           --         --               6,237
Property additions....................       118             79           27         --                 224

</TABLE>

Reconciling  adjustments to segment operating  results from internal  management
reporting to consolidated external financial reporting:

(a)  Principally fuel marketing  revenues which are reflected as reductions
     to expenses for internal management reporting purposes.

(b)  Elimination of intersegment transactions.

                                       19

<PAGE>

<TABLE>
                                                 FIRSTENERGY CORP.

                                         CONSOLIDATED STATEMENTS OF INCOME
                                                    (Unaudited)

<CAPTION>
                                                                                      Three Months Ended
                                                                                            March 31,
                                                                                -------------------------------
                                                                                   2004               2003
                                                                                   ----               ----
                                                                          (In thousands, except per share amounts)
REVENUES:
<S>                                                                            <C>                 <C>
   Electric utilities........................................................  $ 2,177,033         $ 2,315,064
   Unregulated businesses....................................................    1,005,541             905,673
                                                                               -----------         -----------
       Total revenues........................................................    3,182,574           3,220,737
                                                                               -----------         -----------

EXPENSES:
   Fuel and purchased power..................................................    1,134,326           1,100,636
   Purchased gas.............................................................      153,528             224,797
   Other operating expenses..................................................      841,615             926,585
   Provision for depreciation and amortization...............................      412,232             376,363
   General taxes.............................................................      179,085             178,067
                                                                               -----------         -----------
       Total expenses........................................................    2,720,786           2,806,448
                                                                               -----------         -----------

INCOME BEFORE INTEREST AND INCOME TAXES......................................      461,788             414,289
                                                                               -----------         -----------

NET INTEREST CHARGES:
   Interest expense..........................................................      172,864             200,261
   Capitalized interest......................................................       (6,470)             (9,152)
   Subsidiaries' preferred stock dividends...................................        5,281              14,542
                                                                               ------------        -----------
       Net interest charges..................................................      171,675             205,651
                                                                               -----------         -----------

INCOME TAXES.................................................................      116,114              94,258
                                                                               -----------         -----------

INCOME BEFORE DISCONTINUED OPERATIONS AND CUMULATIVE
   EFFECT OF ACCOUNTING CHANGE...............................................      173,999             114,380

Discontinued operations (net of income taxes of $3,211,000) (Note 2).........           --               1,975

Cumulative effect of accounting change (net of income taxes of
   $72,516,000) (Note 2).....................................................           --             102,147
                                                                               -----------         -----------

NET INCOME...................................................................  $   173,999         $   218,502
                                                                               ===========         ===========

BASIC EARNINGS PER SHARE OF COMMON STOCK:
   Income before discontinued operations and cumulative effect
     of accounting change....................................................        $0.53               $0.39
   Discontinued operations (Note 2)..........................................           --                  --
   Cumulative effect of accounting change (Note 2)...........................           --                0.35
                                                                                     -----               -----
   Net income................................................................        $0.53               $0.74
                                                                                     =====               =====

WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING..........................      327,057             293,886
                                                                                   =======             =======

DILUTED EARNINGS PER SHARE OF COMMON STOCK:
   Income before discontinued operations and cumulative effect
     of accounting change....................................................        $0.53               $0.39
   Discontinued operations (Note 2)..........................................           --                  --
   Cumulative effect of accounting change (Note 2)...........................           --                0.35
                                                                                     -----               -----
   Net income................................................................        $0.53               $0.74
                                                                                     =====               =====

WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING........................      329,034             294,877
                                                                                   =======             =======

DIVIDENDS DECLARED PER SHARE OF COMMON STOCK.................................       $0.375              $0.375
                                                                                    ======              ======


<FN>
The preceding Notes to Consolidated  Financial  Statements as they relate to FirstEnergy Corp. are an integral
part of these statements.
</FN>

                                                      20

</TABLE>

<PAGE>

<TABLE>

                                               FIRSTENERGY CORP.

                                          CONSOLIDATED BALANCE SHEETS
                                                  (Unaudited)
<CAPTION>
                                                                                            March 31,    December 31,
                                                                                              2004          2003
                                                                                          ---------------------------
                                                                                                (In thousands)
                                         ASSETS
CURRENT ASSETS:
<S>                                                                                       <C>             <C>
   Cash and cash equivalents.........................................................     $   280,269     $   113,975
   Receivables-
     Customers (less accumulated provisions of $51,127,000 and $50,247,000
       respectively, for uncollectible accounts)......................................        937,026       1,000,259
     Other (less accumulated provisions of $30,257,000 and $18,283,000
       respectively, for uncollectible accounts)......................................        295,728         505,241
   Letter of credit collateralization.................................................        277,763              --
   Materials and supplies, at average cost-
     Owned............................................................................        337,473         325,303
     Under consignment................................................................         90,303          95,719
   Prepayments and other..............................................................        253,180         202,814
                                                                                          -----------     -----------
                                                                                            2,471,742       2,243,311
                                                                                          -----------     -----------
PROPERTY, PLANT AND EQUIPMENT:
   In service.........................................................................     21,917,840      21,594,746
   Less--Accumulated provision for depreciation.......................................      9,242,621       9,105,303
                                                                                          -----------     -----------
                                                                                           12,675,219      12,489,443
   Construction work in progress......................................................        583,927         779,479
                                                                                          -----------     -----------
                                                                                           13,259,146      13,268,922
                                                                                          -----------     -----------
INVESTMENTS:
   Nuclear plant decommissioning trusts...............................................      1,419,743       1,351,650
   Investments in lease obligation bonds .............................................        968,039         989,425
   Letter of credit collateralization ................................................             --         277,763
   Other..............................................................................        919,430         878,853
                                                                                          -----------     -----------
                                                                                            3,307,212       3,497,691
                                                                                          -----------     -----------
DEFERRED CHARGES:
   Regulatory assets..................................................................      6,722,641       7,076,923
   Goodwill...........................................................................      6,117,000       6,127,883
   Other..............................................................................        706,795         695,218
                                                                                          -----------     -----------
                                                                                           13,546,436      13,900,024
                                                                                          -----------     -----------
                                                                                          $32,584,536     $32,909,948
                                                                                          ===========     ===========
                   LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:
   Currently payable long-term debt and preferred stock...............................    $ 1,736,737     $ 1,754,197
   Short-term borrowings .............................................................        133,999         521,540
   Accounts payable...................................................................        548,221         725,239
   Accrued taxes......................................................................        701,458         669,529
   Lease market valuation liability...................................................         84,800          84,800
   Other..............................................................................        760,656         716,862
                                                                                          -----------     -----------
                                                                                            3,965,871       4,472,167
                                                                                          -----------     -----------
CAPITALIZATION:
   Common stockholders' equity-
     Common stock, $.10 par value, authorized 375,000,000 shares-
       329,836,276 shares outstanding.................................................         32,984          32,984
     Other paid-in capital............................................................      7,054,006       7,062,825
     Accumulated other comprehensive loss.............................................       (343,826)       (352,649)
     Retained earnings................................................................      1,655,919       1,604,385
     Unallocated employee stock ownership plan common stock-
       2,692,155 and 2,896,951 shares, respectively...................................        (54,360)        (58,204)
                                                                                          -----------     -----------
         Total common stockholders' equity............................................      8,344,723       8,289,341
   Preferred stock of consolidated subsidiaries not subject to mandatory redemption...        335,123         335,123
   Long-term debt and other long-term obligations.....................................     10,150,067       9,789,066
                                                                                          -----------     -----------
                                                                                           18,829,913      18,413,530
                                                                                          -----------     -----------
NONCURRENT LIABILITIES:
   Accumulated deferred income taxes..................................................      2,137,839       2,178,075
   Asset retirement obligations.......................................................      1,198,132       1,179,493
   Power purchase contract loss liability.............................................      2,597,820       2,727,892
   Retirement benefits................................................................      1,615,837       1,591,006
   Lease market valuation liability...................................................        999,850       1,021,000
   Other..............................................................................      1,239,274       1,326,785
                                                                                          -----------     -----------
                                                                                            9,788,752      10,024,251
                                                                                          -----------     -----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 3)....................................
                                                                                          -----------     -----------
                                                                                          $32,584,536     $32,909,948
                                                                                          ===========     ===========
<FN>
The preceding Notes to Consolidated  Financial  Statements as they relate to FirstEnergy Corp. are an integral
part of these balance sheets.
</FN>

                                                      21

</TABLE>

<PAGE>

<TABLE>

                                               FIRSTENERGY CORP.

                                     CONSOLIDATED STATEMENTS OF CASH FLOWS
                                                  (Unaudited)

<CAPTION>
                                                                                            Three Months Ended
                                                                                                 March 31,
                                                                                          ------------------------
                                                                                          2004              2003
                                                                                          ----              ----
                                                                                              (In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
<S>                                                                                   <C>               <C>
Net income......................................................................      $  173,999        $  218,502
   Adjustments to reconcile net income to net cash from operating activities-
     Provision for depreciation and amortization................................         412,232           376,363
     Nuclear fuel and lease amortization........................................          21,874            14,918
     Other amortization, net....................................................          (4,723)           (4,613)
     Deferred costs recoverable as regulatory assets............................         (83,907)          (94,311)
     Deferred income taxes, net.................................................          12,397            28,141
     Investment tax credits, net................................................          (6,474)           (6,259)
     Cumulative effect of accounting change (Note 2)............................              --          (174,663)
     Income from discontinued operations (Note 2)...............................              --            (1,975)
     Receivables................................................................         272,746            (1,898)
     Materials and supplies.....................................................          (6,754)           11,413
     Accounts payable...........................................................        (177,018)           (7,115)
     Accrued taxes..............................................................          31,929            97,553
     Accrued interest...........................................................          86,636            89,210
     Deferred rents and sale/leaseback valuation liability......................         (16,297)          (17,592)
     Prepayments and other current assets.......................................         (47,031)          (69,673)
     Other......................................................................         (19,986)            4,261
                                                                                       ---------         ---------
       Net cash provided from operating activities..............................         649,623           462,262
                                                                                       ---------         ---------

CASH FLOWS FROM FINANCING ACTIVITIES:
   New Financing-
     Long-term debt.............................................................         581,558           297,696
   Redemptions and Repayments-
     Long-term debt.............................................................        (268,920)         (200,866)
     Short-term borrowings, net.................................................        (387,541)         (237,490)
   Net controlled disbursement activity.........................................         (42,656)           14,444
   Common stock dividend payments...............................................        (122,465)         (110,159)
                                                                                       ---------         ---------
       Net cash used for financing activities...................................        (240,024)         (236,375)
                                                                                       ---------         ---------

CASH FLOWS FROM INVESTING ACTIVITIES:
   Property additions...........................................................        (138,406)         (224,419)
   Nonutility generation trust withdrawals (contributions)......................         (50,614)          106,327
   Contributions to nuclear decommissioning trusts..............................         (25,370)          (25,263)
   Proceeds from asset sales....................................................          11,439            60,572
   Cash investments.............................................................          20,218            24,715
   Other........................................................................         (60,572)          (59,640)
                                                                                       ---------         ---------
       Net cash used for investing activities...................................        (243,305)         (117,708)
                                                                                       ---------         ---------

Net increase in cash and cash equivalents.......................................         166,294           108,179
Cash and cash equivalents at beginning of period................................         113,975           225,932
                                                                                       ---------         ---------
Cash and cash equivalents at end of period......................................       $ 280,269         $ 334,111
                                                                                       =========         =========


<FN>
The preceding Notes to Consolidated  Financial  Statements as they relate to FirstEnergy Corp. are an integral
part of these statements.
</FN>

                                                      22

</TABLE>

<PAGE>


                        REPORT OF INDEPENDENT ACCOUNTANTS



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, 2004, and the related  consolidated
statements  of income and cash flows for each of the  three-month  periods ended
March  31,  2004  and  2003.   These  interim   financial   statements  are  the
responsibility of the Company's management.

We conducted our review in accordance with standards established by the American
Institute  of  Certified  Public  Accountants.  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 generally
accepted  auditing  standards,  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 auditing  standards  generally accepted
in the  United  States  of  America,  the  consolidated  balance  sheet  and the
consolidated  statement  of  capitalization  as of December  31,  2003,  and the
related  consolidated   statements  of  income,   common  stockholders'  equity,
preferred  stock,  cash flows and taxes for the year then  ended (not  presented
herein),  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(F) 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 9 to
those consolidated  financial  statements) dated February 25, 2004, we expressed
an  unqualified  opinion  on those  consolidated  financial  statements.  In our
opinion,  the information set forth in the accompanying  condensed  consolidated
balance sheet as of December 31, 2003, 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 7, 2004

                                       23

<PAGE>


                                FIRSTENERGY CORP.

                     MANAGEMENT'S DISCUSSION AND ANALYSIS OF
                  RESULTS OF OPERATIONS AND FINANCIAL CONDITION


FirstEnergy's Business

          FirstEnergy  Corp.  is a registered  public  utility  holding  company
headquartered  in Akron,  Ohio that provides  regulated and  competitive  energy
services (see Results of Operations - Business Segments).  FirstEnergy continues
to pursue its goal of being the leading  supplier of energy and related services
in portions of the midwest and mid-Atlantic  regions of the United States, where
it sees the best opportunities for growth.  FirstEnergy's  fundamental  business
strategy  remains stable and  unchanged.  While  FirstEnergy  continues to build
toward a strong  regional  presence,  key elements for its strategy are in place
and  management's  focus  continues to be on execution.  FirstEnergy  intends to
continue providing  competitively priced,  high-quality products and value-added
services  - energy  sales  and  services,  energy  delivery,  power  supply  and
supplemental services related to its core business. As the industry changes to a
more competitive environment,  FirstEnergy has taken and expects to take actions
designed  to  create  a  larger,  stronger  regional  enterprise  that  will  be
positioned to compete in the changing energy  marketplace.  FirstEnergy's  eight
electric  utility  operating  companies  provide  transmission  and distribution
services and 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.

          Competitive services are principally provided by FES, FSG, MARBEL, MYR
and  FirstEnergy's  majority owned  FirstCom.  Through its 50% interest in GLEP,
MARBEL is involved in the exploration and production of oil and natural gas, and
transmission  and marketing of natural gas.  Other  subsidiaries  provide a wide
range   of   services,   including   heating,   ventilation,   air-conditioning,
refrigeration, process piping, plumbing, electrical and facility control systems
and  high-efficiency  electrotechnologies.  Telecommunication  services are also
provided - local and long-distance phone service is provided to more than 65,000
customers.  While  competitive  revenues have  increased  since 2001,  regulated
energy services continue to provide, in aggregate, the majority of FirstEnergy's
revenues and earnings.

          Beginning in 2001,  Ohio utilities that offered both  competitive  and
regulated  retail  electric  services  were  required  to  implement a corporate
separation  plan  approved by the PUCO - one which  provided a clear  separation
between regulated and competitive  operations.  FES provides  competitive retail
energy services while the EUOC provide  regulated  transmission and distribution
services.   FGCO,  a  wholly  owned   subsidiary  of  FES,   leases  fossil  and
hydroelectric plants from the EUOC and operates those plants. Under the terms of
the  current  corporate  separation  plan,  the  transfer of  ownership  of EUOC
non-nuclear  generating  assets to FGCO would be substantially  completed by the
end of the  Ohio  market  development  period.  All of  the  EUOC  power  supply
requirements  for the Ohio  Companies (OE, CEI, and TE) and Penn are provided by
FES to satisfy their PLR obligations,  as well as their grandfathered  wholesale
contracts.

          FirstEnergy acquired  international assets through the merger with GPU
in  November  2001.  GPU  Capital  and  its   subsidiaries   provided   electric
distribution  services  in  foreign  countries  (see  Results  of  Operations  -
Discontinued  Operations).  GPU Power and its  subsidiaries  owned and  operated
generation   facilities   in  foreign   countries.   As  of  January  30,  2004,
substantially all of the  international  operations were divested (see Note 5) -
supporting FirstEnergy's commitment to focus on its core electric business.

          FirstEnergy's current focus includes:  (1) enhancing customer service;
(2) optimizing  its generation  portfolio;  (3)  minimizing  unplanned  extended
generation outages;  (4) effectively  managing commodity supplies and risks; (5)
reducing its cost  structure;  (6)  enhancing  its credit  profile and financial
flexibility;  (7)  managing  the  skills and  diversity  of its  workforce;  (8)
continuing safe operations;  and (9) satisfactory resolution of the pending Ohio
rate plan.


Reclassifications

          As  further  discussed  in  Note  8  to  the  Consolidated   Financial
Statements,  amounts for purchased  power,  other operating costs and provisions
for depreciation and amortization in FirstEnergy's 2003 Consolidated  Statements
of Income were  reclassified  to conform with the current year  presentation  of
generation  commodity costs. These  reclassifications  did not change previously
reported 2003 results.  In addition,  as discussed in Note 2 to the Consolidated
Financial Statements,  reporting of discontinued operations also resulted in the
reclassification of revenues, expenses and taxes.

                                       24

<PAGE>

Results of Operations


       Net Income and Earnings Per Share

          Net income in the first  quarter of 2004 was $174 million or $0.53 per
share of common stock (basic and diluted), compared to $218 million or $0.74 per
share of common  stock  (basic and  diluted) in the first  quarter of 2003.  Net
income  in  the  first  quarter  of  2003  included   after-tax   earnings  from
discontinued  operations  of $2 million and an after-tax  credit of $102 million
from the cumulative  effect of an accounting  change (basic and diluted earnings
per share of $0.35) due to the adoption of SFAS 143.  Excluding  the  cumulative
effect of the accounting change in the first quarter of 2003, earnings increased
to $0.53 per share of common stock  (basic and diluted)  from $0.39 per share of
common stock (basic and diluted). Two major factors contributed to this improved
performance -- reduced maintenance costs incurred as part of the extended outage
at  Davis-Besse  (as the plant  prepared for restart in 2004) and the absence of
any  nuclear  refueling  outage in the first  three  months of 2004  versus  one
refueling outage in the same period last year.

          In the third quarter of 2003,  FirstEnergy  completed the issuance and
sale of 32.2  million  shares of common  stock (see Cash  Flows  from  Financing
Activities  below) which were included in the  calculation of earnings per share
on a weighted average basis in the first quarter of 2004. The additional  shares
reduced earnings per share of common stock by $0.06 (basic and diluted).


                                                          Three Months Ended
                                                                March 31,
                                                        -----------------------
        FirstEnergy                                     2004             2003
        -----------------------------------------------------------------------
                                                             (In millions)
        Total revenues.............................    $3,183            $3,221
        Income before interest and income taxes....       462               414
        Income before discontinued operations
           and cumulative effect of accounting change     174               114
        Discontinued operations....................        --                 2
        Cumulative effect of accounting change.....        --               102
        -----------------------------------------------------------------------
        Net Income.................................    $  174            $  218
        -----------------------------------------------------------------------

        Basic Earnings Per Share:
           Income before discontinued operations and
             cumulative effect of accounting change      $0.53             $0.39
           Discontinued operations.................        --                --
           Cumulative effect of accounting change..        --               0.35
        ------------------------------------------------------------------------
        Net Income.................................      $0.53             $0.74
        ========================================================================

        Diluted Earnings Per Share:
           Income before discontinued operations and
             cumulative effect of accounting change      $0.53             $0.39
           Discontinued operations.................        --                --
           Cumulative effect of accounting change..        --               0.35
        ------------------------------------------------------------------------
        Net Income.................................      $0.53             $0.74
        ========================================================================


      Results of  Operations - First Quarter of 2004 Compared With the First
      Quarter of 2003

          Total  revenues  decreased  $38 million in the first  quarter of 2004,
compared to the same period last year.  The sources of changes in total revenues
are summarized in the following table:

                                       25

<PAGE>

                                                  Three Months Ended
                                                       March 31,
                                                  ------------------   Increase
           Sources of Revenue Changes               2004      2003    (Decrease)
           ---------------------------------------------------------------------
                                                       (In millions)
           Retail Electric Sales:
             EUOC - Wires and shopping deferrals $ 1,159    $ 1,213     $ (54)
                                   - Generation      758        785       (27)
             FES..............................       171        121        50
           Wholesale Electric Sales:
             EUOC.............................       124        221       (97)
             FES..............................       444        284       160
           ------------------------------------------------------------------
           Electric Sales.....................     2,656      2,624        32
           ------------------------------------------------------------------
           Transmission Revenues..............        76          9        67
           Gas Sales..........................       165        245       (80)
           Other Revenues:
            Regulated services................        60         86       (26)
            Competitive services..............       220        222        (2)
           International......................        --          8        (8)
           Other..............................         6         27       (21)
           -------------------------------------------------------------------
           Total Revenues.....................    $3,183     $3,221     $ (38)
           ===================================================================


          Changes in electric  generation sales and  distribution  deliveries in
the first  quarter of 2004 from the same quarter of 2003 are  summarized  in the
following table:

                                                               Increase
                   Changes in KWH Sales                       (Decrease)
                   -----------------------------------------------------
                   Electric Generation Sales:
                    Retail -
                      EUOC..................................    (6.2)%
                      FES...................................    24.4 %
                    Wholesale...............................    19.5 %
                   -----------------------------------------------------

                   Total Electric Generation Sales..........     4.1 %
                   =====================================================

                   EUOC Distribution Deliveries:
                    Residential.............................    (0.2)%
                    Commercial..............................      -- %
                    Industrial..............................     0.8 %
                   -----------------------------------------------------

                   Total Distribution Deliveries............     0.2 %
                   =====================================================

          Retail  sales by  FirstEnergy's  EUOC  remain  the  largest  source of
revenues,  contributing  over  70% of  electric  revenues  and over 60% of total
revenues.  The following major factors  contributed to the $81 million reduction
in retail electric revenues from FirstEnergy's regulated services segment in the
first quarter of 2004 compared to the same period in 2003.

                   Sources of the Changes in EUOC Retail Electric Revenue
                   ------------------------------------------------------
                   Increase (Decrease)                     (In millions)
                   ------------------------------------------------------
                   Changes in Demand:
                     Alternative suppliers..................   $(56)
                     Economic and other  ...................      3
                   ------------------------------------------------------
                                                                (53)
                   ------------------------------------------------------
                   Changes in Price:
                     Rate changes...........................    (32)
                     Shopping credit........................     (7)
                     Rate mix and other.....................     11
                   ------------------------------------------------------
                                                                (28)
                   ------------------------------------------------------
                   Net Decrease.............................  $ (81)
                   ======================================================


          Reductions in both demand and prices  contributed to lower EUOC retail
electric  revenues.  Customers  shopping in  FirstEnergy's  franchise  areas for
alternative  energy suppliers remained the largest single factor for the reduced
demand.  Alternative  suppliers  provided 24.1% of the total energy delivered to
retail  customers  in the first  quarter of 2004,  compared to 18.9% in the same
period of 2003.  Distribution  throughput increased slightly.  Milder weather in
the first  quarter of 2004 compared to the unusually  cold  temperatures  in the
first quarter of 2003 contributed to reduced  residential  deliveries.  However,
economic and other factors contributed to increased industrial deliveries in the
first  quarter of 2004  compared to the same period last year. On July 25, 2003,
the NJBPU  announced  its JCP&L base  electric  rate  proceeding  decision  (see
Regulatory  Matters - New Jersey),  which  reduced  JCP&L's  distribution  rates
effective August 1, 2003. The lower rates reduced revenues by $32 million in the
first  quarter  of 2004.  EUOC sales to  wholesale  customers  decreased  by $97

                                       26

<PAGE>

million on a 44.1% reduction in kilowatt-hour  sales - JCP&L's sales represented
substantially all of the decrease.

          Electric  sales  by FES  increased  by  $210  million  primarily  from
additional spot sales to the wholesale  market ($160  million).  Higher electric
sales  to the  wholesale  market  resulted  from  an 11%  increase  in  internal
generation available from FirstEnergy's nuclear (15%) and fossil (9%) generating
plants.  Retail sales increased by $50 million,  primarily from customers within
FirstEnergy's  Ohio franchise  areas  switching to FES under Ohio's  electricity
choice program.

          FirstEnergy's  regulated and unregulated  subsidiaries record purchase
and sales  transactions with PJM on a gross basis in accordance with EITF 99-19.
This gross basis  classification  of revenues and costs may not be comparable to
other energy  companies that operate in regions that have not  established  ISOs
and  do  not  meet  EITF  99-19  criteria.  The  aggregate  purchase  and  sales
transactions  for the three months ended March 31, 2004 and 2003 are  summarized
as follows:

                                              Three Months Ended
                                                   March 31,
                                            ----------------------
                                            2004              2003
           -------------------------------------------------------
                                                 (In millions)
           Sales.........................    $366            $336
           Purchases.....................     330             361
           --------------------------------------------------------

          FirstEnergy's  revenues  on  the  Consolidated  Statements  of  Income
include  wholesale  electricity  sales  revenues  from PJM from power  sales (as
reflected in the table above) during  periods when it had  additional  available
power capacity. Revenues also include sales by FirstEnergy of power sourced from
the PJM  (reflected  as  purchases in the table  above)  during  periods when it
required  additional power to meet  FirstEnergy's  retail load requirements and,
secondarily, to sell to the wholesale market.

          Natural  gas  sales  were  $80  million  lower  primarily  due  to the
expiration of FES customer  choice program  contracts and reduced sales to large
industrial and commercial  customers.  Sales to large  commercial and industrial
customers  declined  in the first  quarter of 2004 from the same  period in 2003
reflecting fewer customers and more moderate temperatures.

          The  generation  margin in the first  quarter of 2004  improved by $53
million  compared  to the same period in 2003 as  electric  generation  revenues
increased  faster than the related  costs for fuel and purchased  power.  Higher
electric generation sales resulted from additional sales to the wholesale market
which  benefited from increased  internal  generation.  The improved  generation
margin  occurred  despite higher  replacement  power costs  associated  with the
extended Davis-Besse outage (see Davis-Besse  Restoration below). The gas margin
decreased $9 million on falling sales.

<TABLE>
<CAPTION>
                                                                        Three Months Ended
                                                                          March 31,
                                                                   ----------------------         Increase
       Energy Revenue Net of Fuel and Purchased Power              2004              2003        (Decrease)
       ----------------------------------------------------------------------------------------------------
                                                                               (In millions)
<S>                                                               <C>               <C>               <C>
       Electric generation revenue...........................     $1,497            $1,411            $86
       Fuel and purchased power..............................      1,134             1,101             33
       --------------------------------------------------------------------------------------------------
       Net...................................................        363               310             53
       --------------------------------------------------------------------------------------------------

       Gas revenue(1)........................................        158               238            (80)
       Purchased gas.........................................        154               225            (71)
       --------------------------------------------------------------------------------------------------
       Net...................................................          4                13             (9)
       --------------------------------------------------------------------------------------------------
       Total Net.............................................    $   367           $   323            $44
       ==================================================================================================
       (1) Excludes 50% share of GLEP earnings.
</TABLE>

          Other  factors  contributing  to the $48  million  increase  in income
before interest and taxes include:

          o   Lower nuclear production costs of $72 million primarily as a
              result of no nuclear  refueling outages in the first quarter
              of 2004  compared to one  refueling  outage at Beaver Valley
              Unit 1 in  last  year's  first  quarter  ($32  million)  and
              reduced  incremental  maintenance  costs at the  Davis-Besse
              Plant ($35 million) related to its restart;

          o   A net decrease of $19 million in other operating expenses as
              a result of reduced  postretirement  benefit  plan  expenses
              (see   Postretirement   Plans  below)   offset  in  part  by
              additional  severance costs and increased  benefit costs for
              active employees; and

                                       27

<PAGE>

          o   Lower non-nuclear  operating expenses  primarily  reflecting
              deferred  planned  outage  work  at   FirstEnergy's   fossil
              generating units ($10 million).

          Partially offsetting these lower costs were three factors:

          o   Reduced revenues from distribution deliveries ($54 million);

          o   Charges for depreciation and amortization  that increased by
              $36 million  primarily due to: higher charges resulting from
              increased   amortization   of  the  Ohio   transition   plan
              regulatory assets ($23 million),  reduced shopping incentive
              deferrals  under the Ohio  transition  plan ($4 million) and
              additional stranded cost amortization for Met-Ed and Penelec
              ($22 million).  Partially  offsetting  these  increases were
              reduced  depreciation  rates  resulting  from the JCP&L rate
              case ($11 million); and

          o   Higher energy delivery costs of $10 million  principally due
              to increased tree trimming activities and to a lesser extent
              JCP&L's accelerated reliability program.

          Income before  discontinued  operations and the  cumulative  effect of
accounting  changes  increased $60 million from the comparable period last year.
The change  reflects  reduced net interest  charges of $34 million and increased
income  taxes of $22 million in addition to the  changes  discussed  above.  The
decrease  in  interest  expense  is the  result  of  debt  and  preferred  stock
redemptions and other financing  activities.  Proceeds from the issuance of 32.2
million  shares of common stock in September 2003  accelerated  the repayment of
debt.  Redemption  and  refinancing  activities  for  debt and  preferred  stock
aggregated  approximately  $653 million  during the first  quarter of 2004.  The
redemption and refinancing  activities and pollution control note repricings are
expected  to  result in  annualized  savings  of $5  million.  FirstEnergy  also
exchanged existing  fixed-rate  payments on outstanding debt (notional amount of
$1.35 billion at March 31, 2004) for short-term  variable rate payments  through
interest  rate swap  transactions  (see Market Risk  Information - Interest Rate
Swap Agreements  below). Net interest charges were reduced by $11 million in the
first quarter of 2004 as a result of these swaps.

       Discontinued Operations

          Net income in the first  quarter of 2003 included  after-tax  earnings
from discontinued  operations of $2 million reflecting the  reclassification  of
revenues and expenses  associated with divestitures of its Argentina and Bolivia
international  businesses and the FSG subsidiaries,  Colonial  Mechanical,  Webb
Technologies and Ancoma, Inc., as well as NEO.

       Cumulative Effect of Accounting Change

          Results in the first quarter of 2003  included an after-tax  credit to
net income of $102  million  recorded  upon the  adoption of SFAS 143 in January
2003.  FirstEnergy  identified applicable legal obligations as defined under the
new standard for nuclear power plant decommissioning and reclamation of a sludge
disposal pond at the Bruce Mansfield  Plant. As a result of adopting SFAS 143 in
January 2003,  asset  retirement  costs of $602 million were recorded as part of
the  carrying  amount of the related  long-lived  asset,  offset by  accumulated
depreciation  of $415  million.  The ARO  liability  at the date of adoption was
$1.11 billion,  including accumulated accretion for the period from the date the
liability  was  incurred  to the date of  adoption.  As of  December  31,  2002,
FirstEnergy   had  recorded   decommissioning   liabilities  of  $1.24  billion.
FirstEnergy expects  substantially all of its nuclear  decommissioning costs for
Met-Ed, Penelec, JCP&L and Penn to be recoverable in rates over time. Therefore,
FirstEnergy  recognized a regulatory  liability of $185 million upon adoption of
SFAS 143 for the transition  amounts related to establishing the ARO for nuclear
decommissioning for those companies.  The remaining cumulative effect adjustment
for  unrecognized  depreciation  and  accretion  offset by the  reduction in the
liabilities  and  the  reversal  of  accumulated  estimated  removal  costs  for
non-regulated  generation assets, was a $175 million increase to income, or $102
million net of income taxes.

       Postretirement Plans

          Resurgent equity markets in 2003,  amendments to FirstEnergy's  health
care  benefits plan in the first quarter of 2004 and the new Medicare Act signed
by  President  Bush in  December  2003  combined  to reduce  pensions  and other
postretirement  costs -- despite  continued  increases  in health care costs and
projected trend rates.  Combined,  these employee benefit expenses  decreased by
$26  million in the first  quarter of 2004  compared to the same period in 2003.
The  following  table  summarizes  the net pension and OPEB  expense  (excluding
amounts capitalized) for the three months ended March 31, 2004 and 2003.

                                       28

<PAGE>

                                             Three Months Ended
          Postretirement Benefits Expense(1)        March 31,
          -----------------------------------------------------
                                              2004         2003
                                              ----         ----
                                                (In millions)
            Pension......................      $20          $31
            OPEB.........................       26           41
          -----------------------------------------------------
              Total......................      $46          $72
          =====================================================

          (1).Excludes the capitalized portion of postretirement benefits
              costs (see Note 4 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. See
"Critical  Accounting  Policies  -  Pension  and Other  Postretirement  Benefits
Accounting"  for a  discussion  of  the  impact  of  underlying  assumptions  on
postretirement expenses.

Results of Operations - Business Segments

          FirstEnergy  manages  its  business  as two  separate  major  business
segments - regulated services and competitive  services. In the first quarter of
2004,  management  made  certain  changes in  presenting  results  for these two
segments  (see Note 8). The  regulated  services  segment  no longer  includes a
portion  of  generation  services.   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.  All generation services are now reported
in the  competitive  services  segment.  As a result,  its revenues  include all
generation  electric  sales  revenues  (including  the  generation  services  to
regulated  franchise  customers  who have not chosen an  alternative  generation
supplier)  and all  domestic  unregulated  energy  and  energy-related  services
including  commodity sales (both  electricity and natural gas) in the retail and
wholesale  markets,   marketing,   generation,   commodity  sourcing  and  other
competitive   energy-application  services  such  as  heating,  ventilating  and
air-conditioning.  "Other"  consists  of  interest  expense  related  to holding
company debt;  corporate support services and the international  businesses that
were  substantially  divested by the first  quarter of 2004.  FirstEnergy's  two
major  business  segments  include  all or a portion of the  following  business
entities:

          o   The regulated  services  segment includes the regulated sale
              of electricity and distribution and transmission services by
              its eight  electric  utility  operating  companies  in Ohio,
              Pennsylvania  and New Jersey  (OE,  CEI,  TE,  Penn,  JCP&L,
              Met-Ed, Penelec and ATSI)

          o   The competitive  services  business  segment consists of the
              subsidiaries  (FES,  FSG,  MYR,  MARBEL and  FirstCom)  that
              operate  unregulated energy and  energy-related  businesses,
              including the operation of generation facilities of OE, CEI,
              TE  and  Penn  resulting  from  the   deregulation   of  the
              Companies'  electric  generation  business  (see  Note  6  -
              Regulatory Matters).

          Financial  results  discussed below include revenues and expenses from
transactions among FirstEnergy's  business segments. A reconciliation of segment
financial results to consolidated financial results is provided in Note 8 to the
consolidated financial statements.  Net income (loss) by business segment was as
follows:

                                              Three Months Ended
                                                  March 31,
              Net Income (Loss)              ---------------------
              By Business Segment            2004           2003
              ----------------------------------------------------
                                                (In millions)
              Regulated services.........   $ 216           $ 358
              Competitive services.......      --             (96)
              Other......................     (42)            (44)
              ----------------------------------------------------
              Total......................   $ 174           $ 218
              ====================================================


       Regulated Services - First Quarter 2004 versus First Quarter 2003

          Financial results for the regulated services segment were as follows:

                                                Three Months Ended
                                                     March 31,
                                                -------------------    Increase
Regulated Services                                2004      2003      (Decrease)
--------------------------------------------------------------------------------
                                                        (In millions)
Total revenues...............................   $1,295     $1,309     $  (14)
Income before interest and income taxes.......     468        570       (102)
Income before cumulative effect of accounting
   changes....................................     216        257        (41)
Net Income....................................     216        358       (142)
--------------------------------------------------------------------------------

                                       29

<PAGE>

          The change in operating revenues resulted from the following sources:


                                          Three Months Ended
                                                March 31,
                                         ---------------------       Increase
        Sources of Revenue Changes       2004             2003      (Decrease)
        ----------------------------------------------------------------------
                                                    (In millions)
        Electric sales.............     $1,159         $1,213          $(54)
        Other sales................        136             96            40
        ----------------------------------------------------------------------
        Total Sales................     $1,295         $1,309          $(14)
        ======================================================================


          The decrease in electric revenues resulted from:

          o   A net  decrease  of $54  million  in  retail  sales -- a $58
              million  decrease in revenues from  distribution  deliveries
              partially  offset  by  a $4  million  decrease  in  shopping
              incentives to customers.

          o   A net $40 million  increase in other sales  primarily due to
              higher transmission revenues.

          Lower revenues  combined with increased  expenses  resulted in an $102
million  decrease in income before  interest and income taxes.  Higher  expenses
included  a  $53  million   increase  in  operating   expenses  from  additional
transmission   expenses  and  energy   delivery  costs,  as  well  as  increased
depreciation and amortization charges of $38 million.


       Competitive Services - First Quarter 2004 versus First Quarter 2003


          Financial  results  for  the  competitive  services  segment  were  as
follows:

                                                   Three Months Ended
                                                        March 31,
                                                   ------------------  Increase
  Competitive Services                               2004      2003   (Decrease)
--------------------------------------------------------------------------------
                              (In millions)
Total revenues...................................   $1,873    $1,874       $ (1)
Income (Loss) before interest and income tax benefit    13      (146)       159
Income (Loss) before discontinued operations and
   cumulative effect of accounting changes.......       --       (92)        92
Net income (loss)................................       --       (96)        96
--------------------------------------------------------------------------------


          The change in total revenues resulted from the following sources:


                                           Three Months Ended
                                                March 31,
                                           -------------------       Increase
       Sources of Revenue Changes          2004           2003      (Decrease)
       ----------------------------------------------------------------------
                                                    (In millions)
       Electric.......................   $1,497        $1,411            $86
       Natural Gas sales..............      165           245            (80)
       Energy-related sales...........      178           187             (9)
       Other..........................       33            31              2
       ----------------------------------------------------------------------
       Total Revenues.................   $1,873        $1,874            $(1)
       ======================================================================


          The increase in electric revenues resulted from:

          o   Higher retail  generation  sales from sales through customer
              choice  programs  ($50  million)  partially  offset by lower
              generation sales from the EUOC ($27 million); and

          o   Increased  wholesale  revenues  of  $160  million  from  FES
              (primarily  into the spot  market)  offset  in part by a $97
              million decrease in EUOC sales to wholesale customers.

          Natural  gas  sales  were  $80  million  lower  primarily  due  to the
expiration of customer  choice  programs in which FES  participated  and reduced
sales to large  industrial and commercial  customers.  Sales to large commercial
and industrial  customers declined  reflecting fewer customers and more moderate
temperatures than last year.

          The  generation  margin  increased $53 million as electric  generation
revenues  increased  faster than the related costs for fuel and purchased power.
Higher  electric  generation  revenues  resulted  from  additional  sales to the
wholesale  market  which  benefited  from  increased  internal  generation.  The
improved  generation  margin  occurred  despite higher  replacement  power costs
associated with the extended  Davis-Besse  outage (see  Davis-Besse  Restoration
below). The margin on gas sales decreased $9 million on falling sales.  Together
with a higher net energy  margin,  reduced  expenses  contributed  to a net $159

                                       30

<PAGE>

million  increase in income  before  interest and income  taxes.  Major  expense
factors included the following:

          o   Lower nuclear production costs of $72 million primarily as a
              result of no nuclear  refueling outages in the first quarter
              of 2004  compared to one  refueling  outage at Beaver Valley
              Unit 1 in the first  quarter  last year  ($32  million)  and
              reduced  incremental  maintenance  costs at the  Davis-Besse
              Plant ($35 million) related to its restart.

          o   A $10 million  decrease in  non-nuclear  operating  expenses
              primarily  from  deferred  planned  outage  work  at  fossil
              generating units.

          o   Reduced    postretirement   benefit   plan   expenses   (see
              Postretirement  Plans  above)  offset  in part by  increased
              benefit costs for active employees.

Capital Resources and Liquidity

          FirstEnergy's  cash  requirements  in  2004  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  short-term
credit facilities will be used to manage working capital requirements.  Over the
next two years,  FirstEnergy  expects to meet its contractual  obligations  with
cash from operations.  Thereafter,  FirstEnergy  expects to use a combination of
cash from operations and funds from the capital markets.

       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 $1.25 billion of revolving credit facilities.  In the first quarter of
2004,  FirstEnergy received $124 million of cash dividends from its subsidiaries
and paid $122 million in cash common stock dividends to its shareholders.  There
are no material  restrictions on the issuance of cash dividends by FirstEnergy's
subsidiaries.

          As of March 31,  2004,  FirstEnergy  had $280 million of cash and cash
equivalents,  compared  with $114  million as of December  31,  2003.  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 by its  regulated  and  competitive  energy  services  businesses  (see
Results of  Operations  -  Business  Segments  above).  Net cash  provided  from
operating  activities  was $650  million  in the first  quarter of 2004 and $462
million in the first quarter of 2003, summarized as follows:

                                                       Three Months Ended
                                                             March 31,
                                                       --------------------
              Operating Cash Flows                     2004          2003
              -------------------------------------------------------------
                                                          (In millions)
              Cash earnings (1)....................   $  508        $ 363
              Working capital and other............      142           99
              -------------------------------------------------------------

              Total................................   $  650        $ 462
              =============================================================

              (1)Includes net income, depreciation and
                 amortization, deferred income taxes, investment
                 tax credits and major noncash charges.


          Net cash provided from operating activities increased $188 million due
to a $145  million  increase in cash  earnings and a $43 million  increase  from
changes in working capital.  The working capital change resulted  primarily from
the net proceeds from the  settlement of  FirstEnergy's  claim against NRG, Inc.
for the terminated sale of four power plants.

       Cash Flows From Financing Activities

          The following table provides details regarding  security issuances and
redemptions during the first quarter of 2004 and 2003:

                                       31

<PAGE>


                                                           Three Months Ended
                                                                March 31,
                                                           --------------------
        Securities Issued or Redeemed                      2004           2003
        ----------------------------------------------------------------------
                                                                (In millions)
        New Issues
             Pollution control notes...................       $112      $    --
             Senior notes..............................        317          250
             Unsecured notes...........................        153           --
             Long-term revolver........................         --           50
             Other, primarily debt discount............         --           (2)
        -----------------------------------------------------------------------
                                                              $582         $298
        Redemptions
             First mortgage bonds......................        $92          $40
             Pollution control notes...................         --           50
             Secured notes.............................         42          108
             Long-term revolving credit................        135           --
             Other, primarily redemption premiums......         --            3
        -----------------------------------------------------------------------
                                                              $269        $201
        Short-term Borrowings, Net ....................      $(388)       $(237)
        ------------------------------------------------------------------------

          Net cash  used for the  above  financing  activities  declined  by $65
million  in the  first  quarter  of 2004  from the first  quarter  of 2003.  The
decrease  in  funds  used  for  financing  activities  resulted  from  increased
financing of $284 million that exceeded  $219 million of additional  redemptions
and  repayments  during the first quarter of 2004 compared to the same period of
2003.

          FirstEnergy had approximately $134 million of short-term  indebtedness
as of March 31, 2004 compared to  approximately  $522 million as of December 31,
2003.  Available  borrowing  capability  as  of  March  31,  2004  included  the
following:

                                         FirstEnergy
Borrowing Capability                   Holding Company     OE          Total
----------------------------------------------------------------------------
                                                    (In millions)
Long-Term Revolver................         $ 875          $375        $1,250
Utilized..........................          (175)           --          (175)
Letters of Credit.................          (183)           --          (183)
----------------------------------------------------------------------------
Net...............................           517           375           892
----------------------------------------------------------------------------

Short-Term Facilities:
Revolver..........................           375           125           500
Bank .............................            --            34            34
----------------------------------------------------------------------------
...................................           375           159           534
----------------------------------------------------------------------------
Utilized:
Revolver..........................            --            --            --
Bank..............................            --            --            --
----------------------------------------------------------------------------
Net...............................           375           159           534
----------------------------------------------------------------------------
Amount Available..................         $ 892          $534        $1,426
============================================================================


          As of March 31, 2004,  the Ohio  companies  and Penn had the aggregate
capability  to issue  approximately  $3.2 billion of additional  first  mortgage
bonds  (FMB) on the basis of property  additions  and  retired  bonds,  although
unsecured  senior note indentures  entered into by OE and CEI in 2004 limit each
company's  ability to issue secured  debt,  including  FMBs,  subject to certain
exceptions.  JCP&L,  Met-Ed and  Penelec no longer  issue FMB other than (in the
case of JCP&L and Penelec) as collateral  for senior  notes,  since their senior
note indentures  prohibit them (subject to certain  exceptions) from issuing any
debt  which is senior to the  senior  notes.  As of March  31,  2004,  JCP&L and
Penelec had the aggregate  capability to issue $545 million of additional senior
notes using FMB  collateral.  Because  Met-Ed  satisfied  the  provisions of its
senior note  indenture for the release of all FMBs held as collateral for senior
notes in March 2004, it is no longer  required to issue FMBs as  collateral  for
future  issuances of senior notes and  therefore not limited as to the amount of
senior notes it may issue.  Based upon  applicable  earnings  coverage  tests in
their  respective  charters,  OE, Penn, TE and JCP&L could issue a total of $3.4
billion of preferred  stock (assuming no additional debt was issued) as of March
31,  2004.  CEI,  Met-Ed and Penelec  have no  restrictions  on the  issuance of
preferred stock.

          In October  2003,  FirstEnergy  restructured  its $1  billion  364-day
revolving  credit facility through a syndicated bank offering that was completed
on October 23, 2003. The new syndicated FirstEnergy facilities consist of a $375
million  364-day  revolving  credit  facility  and  a  $375  million  three-year
revolving  credit  facility.  Also  on  October  23,  2003,  OE  entered  into a
syndicated $125 million 364-day  revolving credit facility and a syndicated $125
million  three-year  revolving  credit  facility.   Combined  with  an  existing
syndicated  $500  million  three-year  facility  for  FirstEnergy,  maturing  in
November 2004, and an existing syndicated $250 million two-year facility for OE,

                                       32

<PAGE>

maturing in May 2005,  FirstEnergy's  primary syndicated credit facilities total
$1.75 billion.  These  facilities are intended to provide  liquidity to meet the
short-term  working capital  requirements of FE and its subsidiaries.  Available
borrowing capacity under existing  facilities totaled $1.426 billion as of March
31, 2004.

          Borrowings  under these  facilities  are  conditioned  on  FirstEnergy
and/or  OE  maintaining  compliance  with  certain  financial  covenants  in the
agreements.  FirstEnergy,  under  its $375  million  364-day  and  $375  million
three-year  facilities,  and OE, under its $125 million 364-day and $250 million
two-year   facilities,   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. Under its $500 million  three-year
facility,  FirstEnergy  is required  to maintain a debt to total  capitalization
ratio  of no  more  than  0.69  to 1 and a  contractually-defined  fixed  charge
coverage  ratio for the most  recent  fiscal  quarter  of no less than 1.5 to 1.
FirstEnergy and OE are in compliance with all of these financial covenants.  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 its business, its condition (financial or
otherwise), its results of operations, or its prospects.

          None  of  FirstEnergy's  or OE's  primary  credit  facilities  contain
provisions,  whereby their  ability to borrow would be restricted or denied,  or
repayment of outstanding loans under the facilities accelerated,  as a result of
any  change  in  the  credit  ratings  of  FirstEnergy  or  OE  by  any  of  the
nationally-recognized  rating  agencies.  Borrowings  under each of the  primary
facilities do contain "pricing grids",  whereby the cost of funds borrowed under
the  facilities  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 its competitive
companies.  FirstEnergy  Service Company  administers  these two money pools and
tracks surplus funds of FirstEnergy and the respective regulated and competitive
subsidiaries,  as well as  proceeds  available  from  bank  borrowings.  For the
regulated  companies,  available  bank  borrowings  include  $1.75  billion from
FirstEnergy's  and  OE's  revolving  credit  facilities.   For  the  competitive
companies,   available  bank  borrowings  include  only  the  $1.25  billion  of
FirstEnergy's  revolving credit facility.  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. For the regulated
and competitive  money pools,  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 2004 was 1.30% for the regulated  companies' pool and 1.57%
for the competitive companies' pool.

          In   January   and   March  of   2004,   FirstEnergy   executed   four
fixed-to-floating  interest rate swap  agreements  with notional  amounts of $50
million each on underlying EUOC senior notes and subordinated debentures with an
average fixed rate of 5.73%.

          In March 2004,  Met-Ed,  Penelec and Penn completed  on-balance sheet,
receivable  financing  transactions which allow each company to borrow up to $80
million,  $75 million and $25 million,  respectively.  The  borrowing  rates are
based on bank  commercial  paper  rates.  Met-Ed and Penelec are required to pay
annual  facility  fees of 0.30%  on the  entire  finance  limit.  Penn  Power is
required to pay an annual facility fee of 0.40% on the entire finance limit. The
facilities  were undrawn at the end of March 2004.  These  facilities  mature on
March 29, 2005.

          On March 25,  2004,  Met-Ed  issued $250 million  principal  amount of
4.875%  Senior Notes due 2014. A portion of the proceeds were used to redeem $50
million  aggregate  principal  amount of  outstanding  Met-Ed  Medium Term Notes
(MTNs)  having  a  weighted  average  interest  cost of  6.39%,  and to pay down
short-term debt.  Met-Ed also intends to use a portion of the proceeds to redeem
$100 million  principal  amount of Met-Ed Capital  Trust's 7.35% Trust Preferred
Securities  in the second  quarter of 2004 and to pay at  maturity  $40  million
principal amount of Met-Ed's 6.34% MTNs maturing August 27, 2004.

          On March 31, 2004,  Penelec  issued $150 million  principal  amount of
5.125%  Senior  Notes due 2014.  The proceeds of this  transaction  were used to
redeem $125 million principal amount of 5.75% Senior Notes that matured on April
1, 2004 and to repay short-term debt.

          On April 23, 2004,  JCP&L  issued $300 million of 5.625%  Senior Notes
due 2016. The proceeds of this transaction will be used to redeem $40 million of
7.98% JCP&L  Series C MTNs due 2023 and $50 million of 6.78% JCP&L Series C MTNs
due 2005. The remaining  proceeds will be used to fund the mandatory  redemption
of  JCPL's  $160  million  of  7.125%  FMB due  October  1,  2004 and to  reduce
short-term debt.

          On February 6, 2004, Moody's  downgraded  FirstEnergy senior unsecured
debt to Baa3 from Baa2 and downgraded  the senior secured debt of JCP&L,  Met-Ed
and Penelec to Baa1 from A2. Moody's also  downgraded the preferred stock rating
of JCP&L to Ba1 from Baa2 and the  senior  unsecured  rating of  Penelec to Baa2
from A2. The ratings of OE, CEI, TE and Penn were  confirmed.  Moody's said that
the  lower  ratings  were  prompted  by:  "1) high  consolidated  leverage  with
significant  holding company debt, 2) a degree of regulatory  uncertainty in the

                                       33

<PAGE>

service  territories in which the company  operates,  3) risks  associated  with
investigations of the causes of the August 2003 blackout, and related securities
litigation,  and 4) a  narrowing  of  the  ratings  range  for  the  FirstEnergy
operating utilities,  given the degree to which FirstEnergy increasingly manages
the utilities as a single system and the significant financial interrelationship
among the subsidiaries."

          On March 9, 2004, S&P stated that the NRC's permission for FirstEnergy
to restart the Davis-Besse nuclear plant was positive for credit quality because
it would positively affect cash flow by eliminating  replacement power costs and
"demonstrating   management's  ability  to  overcome  operational   challenges."
However, S&P did not change  FirstEnergy's  ratings or outlook because it stated
that financial performance still "significantly lags expectations and management
faces other operational hurdles."

       Cash Flows From Investing Activities

          Net cash flows used for investing  activities  totaled $243 million in
the first  quarter of 2004,  compared to net cash flows of $118 million used for
investing  activities  for the same  period  of 2003.  The $125  million  change
primarily  resulted from a refunding  payment of $51 million to a NUG trust fund
in the first quarter 2004 compared to $106 million of  withdrawals  in the first
quarter of 2003.

           The following table summarizes first quarter 2004 investments by
FirstEnergy's regulated services and competitive services segments:

Summary of First Quarter 2004            Property
Cash Used for Investing Activities       Additions   Investments   Other   Total
--------------------------------------------------------------------------------
Sources (Uses)                                          (In millions)
Regulated Services....................     $ (90)      $(79)(1)    $ (2)  $(171)
Competitive Services..................       (45)        20           2     (23)
Other.................................        (3)       (26)        (20)    (49)
--------------------------------------------------------------------------------

     Total............................     $(138)      $(85)       $(20)  $(243)
================================================================================

          (1) Includes a $51 million refunding payment to a NUG trust fund.


          During the remaining three quarters of 2004, capital  requirements for
property  additions  and capital  leases are expected to be  approximately  $666
million,  including $86 million for nuclear  fuel.  FirstEnergy  has  additional
requirements of approximately $902 million to meet sinking fund requirements for
preferred stock and maturing  long-term debt during the remainder of 2004. These
cash requirements are expected to be satisfied from internal cash and short-term
credit arrangements.

          FirstEnergy's  current forecast reflects expenditures of approximately
$2.3 billion for property  additions and improvements  from 2004-2006,  of which
approximately  $720 million is applicable to 2004.  Investments  for  additional
nuclear fuel during the 2004-2006 period are estimated to be approximately  $315
million,  of which  approximately  $86 million applies to 2004.  During the same
periods,  the Companies'  nuclear fuel investments are expected to be reduced by
approximately $281 million and $91 million, respectively, as the nuclear fuel is
consumed.

          As of March 31, 2004, FirstEnergy had $278 million in deposits pledged
as collateral to secure reimbursement  obligations related to certain letters of
credit  supporting  OE's  obligations  to lessors under the Beaver Valley Unit 2
sale and leaseback arrangements.  The deposits had previously been classified as
a noncurrent investment.  OE expects to replace the cash collateralized LOC with
a structure that would not require cash  collateral.  OE  anticipates  using the
cash from the deposit to repay short term debt in the third  quarter of 2004 and
for other general corporate purposes.

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 letters of credit.

          As of March 31, 2004,  the maximum  potential  future  payments  under
outstanding  guarantees and other assurances  totaled $1.9 billion as summarized
below:

                                       34

<PAGE>

                                                                   Maximum
                 Guarantees and Other Assurances                   Exposure
                 ------------------------------------------------------------
                                                                 (In millions)
                 FirstEnergy Guarantees of Subsidiaries:
                   Energy and Energy-Related Contracts(1)......   $   862
                   Other (2)...................................       149
                 --------------------------------------------------------
                                                                    1,011

                 Surety Bonds..................................       240
                 Letters of Credit (3)(4)......................       677
                 --------------------------------------------------------

                   Total Guarantees and Other Assurances.......   $ 1,928
               ==========================================================

              (1) Issued for a one-year term, with a 10-day
                  termination right by
                  FirstEnergy.
              (2) Issued for various terms.
              (3) Includes letters of credit of $183 million issued
                  for various terms under letter of credit capacity
                  available in FirstEnergy's revolving credit
                  agreement.
              (4) Includes unsecured letters of credit of approximately
                  $216 million pledged in connection with the sale and
                  leaseback of Beaver Valley Unit 2 by CEI and TE, as
                  well as collateralized letters of credit of $278
                  million pledged in connection with the sale and
                  leaseback of Beaver Valley Unit 2 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 activities 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  payment of
cash  collateral  or provision of an LOC may be required.  The  following  table
summarizes collateral provisions as of March 31, 2004:

                                             Collateral Paid
                               Total     -----------------------     Remaining
Collateral Provisions        Exposure    Cash   Letters of Credit   Exposure (1)
--------------------------------------------------------------------------------
                                              (In millions)
Rating downgrade............  $228       $133         $18              $ 77
Adverse event...............   232         --          69               163
--------------------------------------------------------------------------------
Total.......................  $460       $133         $87              $240
================================================================================

       (1)  As of April 12, 2004, FirstEnergy's remaining exposure was $237
            million,  with  $141  million  of cash  and $72  million  of
            letters of credit provided as collateral.


          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.

          Various  contracts  include  credit  enhancements  in the form of cash
collateral,  letters of credit or other  security in the event of a reduction in
credit rating.  Requirements of these provisions vary and typically require more
than one rating reduction to below investment grade by S&P or Moody's to trigger
additional collateralization.

          FirstEnergy  has also  guaranteed the  obligations of the operators of
the TEBSA  project  in  Colombia,  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 the
TEBSA project  lenders a $60 million LOC, which is renewable and declines yearly
based upon the senior  outstanding debt of TEBSA.  This LOC granted  FirstEnergy
the ability to sell its remaining 20.1% interest in Avon.

                                       35

<PAGE>

OFF-BALANCE SHEET ARRANGEMENTS

          FirstEnergy has obligations  that are not included on its Consolidated
Balance Sheets 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, 2004.

          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 $200
million of off-balance sheet financing as of March 31, 2004.

          As of March 31, 2004,  off-balance sheet arrangements  include certain
statutory  business  trusts  created by CEI,  Met-Ed and  Penelec to issue trust
preferred securities aggregating $285 million. These trusts were included in the
consolidated  financial  statements of FirstEnergy  prior to the adoption of FIN
46R, but have subsequently been  deconsolidated  under FIN 46R (see Note 7 - New
Accounting Standards and Interpretations). This deconsolidation has not resulted
in any change in outstanding debt.

          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  executive
officers,  exercises an independent risk oversight function to ensure compliance
with corporate risk management policies and prudent risk management practices.

       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.   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 2004 is  summarized  in the
following table:

                                       36

<PAGE>

<TABLE>
<CAPTION>

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:
<S>                                                                 <C>        <C>       <C>
Outstanding net asset as of January 1, 2004...................      $67        $ 12      $ 79
New contract value when entered...............................       --          --        --
Additions/change in value of existing contracts...............       (4)          6         2
Change in techniques/assumptions..............................       --          --        --
Settled contracts.............................................        1          (6)       (5)
-------------------------------------------------------------------------------------------------

Outstanding net asset as of March 31, 2004 (1)................       64          12        76
-------------------------------------------------------------------------------------------------

Non-commodity Net Assets as of March 31, 2004:
Interest Rate Swaps (2).......................................       --          38        38
-------------------------------------------------------------------------------------------------
Net Assets - Derivatives Contracts as of March 31, 2004 (3)...      $64        $ 50      $114
=================================================================================================

Impact of Changes in Commodity Derivative Contracts: (4)
Income Statement Effects (Pre-Tax)............................      $(1)       $ --      $ (1)
Balance Sheet Effects:
Other Comprehensive Income (Pre-Tax)..........................      $--        $ --      $ --
Regulatory Liability..........................................      $(2)       $ --      $ (2)

</TABLE>

(1)  Includes $59 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.
(3)  Excludes $24 million of derivative contract fair value decrease, as of
     March 31, 2004,  representing  FirstEnergy's  50% share of Great Lakes
     Energy Partners, LLC.
(4)  Represents  the  increase  in value  of  existing  contracts,  settled
     contracts and changes in techniques/assumptions.


          Derivatives are included on the Consolidated Balance Sheet as of March
31, 2004 as follows:


       Balance Sheet Classification               Non-Hedge    Hedge    Total
       -----------------------------------------------------------------------
                                                           (In millions)
        Current-
              Other Assets......................  $  10        $11    $  21
              Other Liabilities.................     (6)        --       (6)

        Non-current-
              Other Deferred Charges............     60         44      104
              Other Noncurrent Liabilities......     --         (5)      (5)
        ----------------------------------------------------------------------

              Net assets........................  $  64        $50    $ 114
        ======================================================================

          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:

<TABLE>
<CAPTION>
Source of Information
- Fair Value by Contract Year             2004(1)    2005       2006       2007    Thereafter   Total
-----------------------------------------------------------------------------------------------------
                                                                 (In millions)
<S>                   <C>                <C>        <C>        <C>        <C>          <C>       <C>
Prices actively quoted(2).............   $ 9        $ 2         $--        $--         $--       $11
Other external sources(3).............    12         10          --         --          --        22
Prices based on models................    --         --          10         10          23        43
-----------------------------------------------------------------------------------------------------

   Total(4)...........................   $21        $12         $10        $10         $23       $76
=====================================================================================================
</TABLE>

(1)  For the last three quarters of 2004.
(2)  Exchange traded.
(3)  Broker quote sheets.
(4)  Includes $59 million in non-hedge commodity derivative contracts which
     are offset by a regulatory liability.

                                       37

<PAGE>

          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, 2004.
Based on derivative  contracts  held as of March 31, 2004, an adverse 10% change
in commodity  prices would decrease net income by  approximately  $1 million for
the next twelve months.

       Interest Rate Swap Agreements

          During  the  first   quarter  of  2004,   FirstEnergy   entered   into
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 a 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. As a result of
the differences between fixed and variable debt rates,  interest expense was $11
million  lower in the first  quarter  of 2004.  As of March 31,  2004,  the debt
underlying the interest rate swaps had a weighted average fixed interest rate of
5.44%, which the swaps have effectively  converted to a current weighted average
variable interest rate of 2.11%.

<TABLE>
       Interest Rate Swaps

<CAPTION>
                               March 31, 2004                        December 31, 2003
                          ----------------------------         -----------------------------
                          Notional    Maturity     Fair        Notional    Maturity     Fair
Denomination              Amount       Date       Value        Amount       Date       Value
--------------------------------------------------------------------------------------------
                                               (Dollars in millions)
Fixed to Floating Rate
<S>                        <C>         <C>       <C>           <C>         <C>         <C>
  (Fair value hedges)      $200        2006      $  5          $200        2006        $  1
                            100        2008         2            50        2008          --
                            100        2010         1           100        2010           1
                            100        2011         6           100        2011           1
                            450        2013        14           350        2013          (1)
                            150        2015        (3)          150        2015         (10)
                            150        2018         9           150        2018           1
                             50        2019         4            50        2019           1
                             50        2031      __--
-------------------------------------------------------------------------------------------
                         $1,350                   $38        $1,150                    $ (6)
--------------------------------------------------------------------------------------------
Floating to Fixed Rate (1)
  (Cash flow hedges)                                         $    7        2005        $ --
-------------------------------------------------------------------------------------------
</TABLE>

(1)    FirstEnergy  no longer had the cash flow hedges as of January 30, 2004
       as a result of the divestiture of Los Amigos Leasing Company,  Ltd.. -
       a subsidiary of GPU Power.

       Equity Price Risk

          Included  in  nuclear  decommissioning  trusts are  marketable  equity
securities  carried at their market value of approximately $821 million and $779
million as of March 31, 2004 and December 31, 2003, respectively. A hypothetical
10% decrease in prices quoted by stock  exchanges would result in an $82 million
reduction in fair value as of March 31, 2004.

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  stringent  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 S&P rating for energy
contract  counterparties  of  "BBB."  As of March 31,  2004 the  largest  credit
concentration to any counterparty was 8% - which is a currently rated investment
grade counterparty.

Outlook

       Business Organization

          FirstEnergy's business is managed as two distinct operating segments -
a competitive  services segment and a regulated  services segment.  FES provides
competitive retail energy services while the EUOC provide regulated transmission
and distribution services. FGCO, a wholly owned subsidiary of FES, leases fossil
and  hydroelectric  plants from the EUOC and operates those plants.  FirstEnergy
expects the transfer of ownership of EUOC nonnuclear  generating  assets to FGCO

                                       38

<PAGE>

will be  substantially  completed  by the  end of the  Ohio  market  development
period.  All of the EUOC power supply  requirements  for the Ohio  Companies and
Penn  are  provided  by FES  to  satisfy  their  PLR  obligations,  as  well  as
grandfathered wholesale contracts.

       Regulatory Matters

          In Ohio,  New Jersey and  Pennsylvania,  laws  applicable  to electric
industry  deregulation  included  similar  provisions which are reflected in the
EUOC's respective state regulatory plans.  However,  despite these similarities,
the  specific  approach  taken by each  state and for each of the EUOCs  varies.
Those provisions include:

          o   allowing  the  EUOC's  electric  customers  to select  their
              generation suppliers;

          o   establishing  PLR  obligations  to  customers  in the EUOC's
              service areas;

          o   allowing recovery of transition costs (sometimes referred to
              as  stranded  investment)  not  otherwise  recoverable  in a
              competitive generation market;

          o   itemizing  (unbundling)  the price of  electricity  into its
              component  elements -  including  generation,  transmission,
              distribution and transition costs recovery charges;

          o   deregulating the electric generation businesses;

          o   continuing   regulation  of  the  EUOC's   transmission  and
              distribution systems; and

          o   requiring corporate  separation of regulated and unregulated
              business activities.

          Regulatory assets are costs which the respective  regulatory  agencies
have authorized for recovery from customers in future periods and,  without such
authorization,  would have been  charged  to income  when  incurred.  All of the
regulatory  assets are expected to continue to be recovered under the provisions
of the  respective  transition  and  regulatory  plans as discussed  below.  The
regulatory assets of the individual companies are as follows:


                                  March 31,       December 31,
   Regulatory Assets                2004              2003           (Decrease)
   ----------------------------------------------------------------------------
                                                  (In millions)
   OE............................   $1,348            $1,451           $ (103)
   CEI...........................    1,022             1,056              (34)
   TE............................      432               459              (27)
   Penn..........................       15                28              (13)
   JCP&L.........................    2,457             2,558             (101)
   Met-Ed........................      990             1,028              (38)
   Penelec.......................      459               497              (38)
   ---------------------------------------------------------------------------
   Total.........................   $6,723            $7,077            $(354)
   ===========================================================================


   Regulatory assets by source are as follows:

                                             March 31,  December 31,   Increase
   Regulatory Assets By Source                 2004        2003       (Decrease)
   -----------------------------------------------------------------------------
                                                        (In millions)
   Regulatory transition charge.............   $6,088      $6,427       $(339)
   Customer shopping incentives.............      413         371          42
   Customer receivables for future income taxes   315         340         (25)
   Societal benefits charge.................       81          81          --
   Loss on reacquired debt..................       74          75          (1)
   Postretirement benefits..................       74          77          (3)
   Nuclear decommissioning, decontamination
     and spent fuel disposal costs..........     (106)        (96)        (10)
   Component removal costs..................     (327)       (321)         (6)
   Property losses and unrecovered plant costs     65          70          (5)
   Other....................................       46          53          (7)
   ---------------------------------------------------------------------------
   Total....................................   $6,723      $7,077       $(354)
   ===========================================================================

                                       39


<PAGE>

       Reliability Initiatives

          On  October  15,  2003,  NERC  issued a Near  Term  Action  Plan  that
contained  recommendations  for all control areas and  reliability  coordinators
with  respect  to  enhancing  system   reliability.   Approximately  20  of  the
recommendations  were directed at the FirstEnergy  companies and broadly focused
on  initiatives  that are  recommended  for  completion  by summer  2004.  These
initiatives  principally  relate to  changes in voltage  criteria  and  reactive
resources  management;  operational  preparedness  and action  plans;  emergency
response   capabilities;   and,  preparedness  and  operating  center  training.
FirstEnergy   presented  a  detailed   compliance  plan  to  NERC,   which  NERC
subsequently  endorsed on May 7, 2004, and the various  initiatives are expected
to be completed no later than June 30, 2004.

          On February 26-27, 2004, certain FirstEnergy companies participated in
a NERC Control Area Readiness Audit. This audit, part of an announced program by
NERC to review  control area  operations  throughout  much of the United  States
during 2004, is an  independent  review to identify areas for  improvement.  The
final  audit  report was  completed  on April 30,  2004.  The report  identified
positive  observations  and included  various  recommendations  for improvement.
FirstEnergy  is currently  reviewing the audit results and  recommendations  and
expects to  implement  those  relating to summer  2004 by June 30.  Based on its
review thus far, FirstEnergy believes that none of the recommendations  identify
a  need  for  any  incremental  material  investment  or  upgrades  to  existing
equipment.  FirstEnergy notes, however, that NERC 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.

          On March 1, 2004, certain  FirstEnergy  companies filed, in accordance
with a November 25, 2003 order from the PUCO, their plan for addressing  certain
issues  identified  by the PUCO from the U.S. - Canada Power System  Outage Task
Force  interim  report.  In  particular,   the  filing  addressed   upgrades  to
FirstEnergy's  control room computer  hardware and software and  enhancements to
the  training of control  room  operators.  The PUCO will review the plan before
determining the next steps, if any, in the proceeding.

          On April 22,  2004,  FirstEnergy  filed  with FERC the  results of the
FERC-ordered independent study of part of Ohio's power grid. The study examined,
among other things,  the reliability of the transmission grid in critical points
in  the  Northern  Ohio  area  and  the  need,   if  any,  for  reactive   power
reinforcements  during summer 2004 and 2005.  FirstEnergy is currently reviewing
the  results  of that  study and  expects  to  complete  the  implementation  of
recommendations  relating to 2004 by this summer.  Based on its review thus far,
FirstEnergy  believes that the study does not recommend any incremental material
investment or 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.

          With respect to each of the  foregoing  initiatives,  FirstEnergy  has
requested and NERC has agreed to provide, a technical assistance team of experts
to provide ongoing guidance and assistance in implementing and confirming timely
and successful completion.

       Ohio

          FirstEnergy's  transition plan for the Ohio EUOC included approval for
recovery of transition costs, including regulatory assets, through no later than
2006 for OE,  mid-2007 for TE and 2008 for CEI,  except where a longer period of
recovery is provided for in the settlement agreement;  granting preferred access
over its subsidiaries to nonaffiliated  marketers,  brokers and aggregators,  to
1,120 MW of generation  capacity through 2005 at established prices for sales to
the Ohio  EUOC's  retail  customers;  and  freezing  customer  prices  through a
five-year  market  development  period  (2001-2005),  except for certain limited
statutory  exceptions  including a 5% reduction in the price of  generation  for
residential customers. In February 2003, the Ohio EUOC were authorized increases
in revenues  aggregating  approximately $50 million (OE - $41 million,  CEI - $4
million and TE - $5 million) to recover  their higher tax costs  resulting  from
the Ohio deregulation legislation.

          The Ohio EUOC  customers  choosing  alternative  suppliers  receive an
additional  incentive applied to the shopping credit  (generation  component) of
45%  for  residential  customers,  30%  for  commercial  customers  and  15% for
industrial  customers.  The  amount of the  incentive  is  deferred  for  future
recovery  from  customers.  Subject to  approval by the PUCO,  recovery  will be
accomplished by extending the respective transition cost recovery period.

          On October 21, 2003, the Ohio EUOC filed an application  with the PUCO
to establish  generation service rates beginning January 1, 2006, in response to
expressed concerns by the PUCO about price and supply uncertainty  following the
end of the market development period. The filing included two options:

          o   A  competitive  auction,  which would  establish a price for
              generation that customers would be charged during the period
              covered by the auction, or

                                       40


<PAGE>

          o   A  Rate  Stabilization  Plan,  which  would  extend  current
              generation prices through 2008, ensuring adequate generation
              supply at stable  prices,  and  continuing  the Ohio  EUOC's
              support  of  energy  efficiency  and  economic   development
              efforts.

          Under  the first  option,  an  auction  would be  conducted  to secure
generation service for the Ohio EUOC's customers.  Beginning in 2006,  customers
would pay market prices for generation as determined by the auction.

          Under the Rate Stabilization  Plan option,  customers would have price
and supply  stability  through  2008 - three years  beyond the end of the market
development period - as well as the benefits of a competitive  market.  Customer
benefits would include:  customer  savings by extending the current five percent
discount on generation  costs and other customer  credits;  maintaining  current
distribution  base  rates  through  2007;  market-based  auctions  that  may  be
conducted  annually to ensure that  customers pay the lowest  available  prices;
extension  of the Ohio  EUOC's  support of  energy-efficiency  programs  and the
potential for continuing the program to give preferred  access to  nonaffiliated
entities to generation  capacity if shopping drops below 20%. Under the proposed
plan, the Ohio EUOC are requesting:

          o   Extension of the transition cost amortization  period for OE
              from 2006 to 2007;  for CEI from 2008 to mid-2009 and for TE
              from mid-2007 to mid-2008;

          o   Deferral  of  interest  costs  on the  accumulated  shopping
              incentives  and  other  cost  deferrals  as  new  regulatory
              assets; and

          o   Ability to initiate a request to increase  generation  rates
              under certain limited conditions.

          On January 7, 2004,  the PUCO staff filed  testimony  on the  proposed
rate plan  generally  supporting the Rate  Stabilization  Plan as opposed to the
competitive  auction proposal.  Hearings began on February 11, 2004. On February
23, 2004,  after  consideration  of PUCO Staff comments and testimony as well as
those  provided by some of the  intervening  parties,  FirstEnergy  made certain
modifications  to the Rate  Stabilization  Plan. Oral arguments were held before
the PUCO on April 21 and a decision is  expected  from the PUCO in the Spring of
2004.

       New Jersey

          Under New Jersey  transition  legislation,  all electric  distribution
companies  were  required to file rate cases to determine the level of unbundled
rate components to become effective August 1, 2003. JCP&L's two August 2002 rate
filings requested  increases in base electric rates of approximately $98 million
annually  and  requested  the recovery of deferred  energy  costs that  exceeded
amounts being recovered under the current MTC and SBC rates; one proposed method
of recovery of these costs is the  securitization of the deferred balance.  This
securitization  methodology  is similar to the Oyster Creek  securitization.  In
July 2003, the NJBPU announced its JCP&L base electric rate proceeding  decision
which reduced JCP&L's annual  revenues by  approximately  $62 million  effective
August 1, 2003. The NJBPU decision also provided for an interim return on equity
of 9.5% on  JCP&L's  rate base for the next six to twelve  months.  During  that
period, JCP&L will initiate another proceeding to request recovery of additional
costs  incurred to enhance system  reliability.  In that  proceeding,  the NJBPU
could increase the 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. The revenue decrease in the decision  consists of
a $223  million  decrease in the  electricity  delivery  charge,  a $111 million
increase  due to the  August  1, 2003  expiration  of  annual  customer  credits
previously  mandated  by the New Jersey  transition  legislation,  a $49 million
increase in the MTC tariff  component,  and a net $1 million increase in the SBC
charge.  The MTC allowed for the  recovery  of $465  million in deferred  energy
costs over the next ten years on an interim basis, thus disallowing $153 million
of the $618 million provided for in a preliminary  settlement  agreement between
certain parties. As a result,  JCP&L recorded charges to net income for the year
ended  December 31, 2003,  aggregating  $185 million  ($109  million net of tax)
consisting  of the $153  million  deferred  energy  costs and  other  regulatory
assets. JCP&L filed a motion for rehearing and reconsideration with the NJBPU on
August 15, 2003 with respect to the following  issues:  (1) the  disallowance of
the $153  million  deferred  energy  costs;  (2) the  reduced  rate of return on
equity; and (3) $42.7 million of disallowed costs to achieve merger savings.  On
October 10,  2003,  the NJBPU held the motion in abeyance  until the final NJBPU
decision and order is issued. This is expected to occur in the second quarter of
2004.

          On July  5,  2003,  JCP&L  experienced  a  series  of  34.5  kilo-volt
sub-transmission  line faults that  resulted in outages on the New Jersey shore.
The NJBPU  instituted an investigation  into these outages,  and directed that a
Special Reliability Master be hired to oversee the investigation. On December 8,
2003, the Special Reliability Master issued his Interim Report recommending that
JCP&L implement a series of actions to improve  reliability in the area affected
by the  outages.  The NJBPU  adopted the  findings  and  recommendations  of the
Interim  Report on  December  17,  2003,  and  ordered  JCP&L to  implement  the
recommended  actions on a staggered basis,  with initial actions to be completed
by March 31,  2004.  JCP&L  expects to spend $12.5  million  implementing  these
actions during 2004. In late 2003, in accordance  with a Settlement  Stipulation
concerning an August 2002 storm outage,  the NJBPU engaged Booth & Associates to
conduct an audit of the planning, operations and maintenance practices, policies

                                       41

<PAGE>

and procedures of JCP&L.  The audit was expanded to include the July 2003 outage
and was completed in January  2004.  JCP&L is awaiting the issuance of the final
audit report and is unable to predict the outcome of the audit; no liability has
been accrued as of March 31, 2004.

          On April 28, 2004,  the NJBPU  directed JCP&L to file testimony by the
end of May 2004,  either  supporting  a  continuation  of the current  level and
duration of the funding of TMI-2 decommissioning costs by New Jersey ratepayers,
or, alternatively, proposing a reduction, termination or capping of the funding.
JCP&L cannot predict the outcome of this matter.

   Pennsylvania

          In June 2001, the PPUC approved the Settlement Stipulation with all of
the major parties in the combined merger and rate proceedings which approved the
FirstEnergy/GPU merger and provided PLR deferred accounting treatment for energy
costs, permitting Met-Ed and Penelec to defer, for future recovery, energy costs
in excess of amounts  reflected in their capped  generation rates retroactive to
January 1, 2001. This PLR deferral accounting  procedure was later reversed in a
February 2002 Commonwealth  Court of Pennsylvania  decision.  The court decision
affirmed  the PPUC  decision  regarding  approval of the merger,  remanding  the
decision  to the  PPUC  only  with  respect  to the  issue  of  merger  savings.
FirstEnergy established reserves in 2002 for Met-Ed's and Penelec's PLR deferred
energy costs which aggregated  $287.1 million,  reflecting the potential adverse
impact of the then pending Pennsylvania Supreme Court decision whether to review
the  Commonwealth  Court  decision.  FirstEnergy  recorded in 2002 an  aggregate
non-cash  charge of $55.8 million  ($32.6  million net of tax) to income for the
deferred costs incurred  subsequent to the merger. The reserve for the remaining
$231.3 million of deferred costs  increased  goodwill by an aggregate net of tax
amount of $135.3 million.

          On April 2,  2003,  the PPUC  remanded  the issue  relating  to merger
savings to the ALJ for hearings,  directed Met-Ed and Penelec to file a position
paper  on  the  effect  of  the  Commonwealth  Court  order  on  the  Settlement
Stipulation  and allowed other parties to file responses to the position  paper.
Met-Ed and  Penelec  filed a letter with the ALJ on June 11,  2003,  voiding the
Stipulation in its entirety and reinstating Met-Ed's and Penelec's restructuring
settlement previously approved by the PPUC.

          On October  2,  2003,  the PPUC  issued an order  concluding  that the
Commonwealth Court reversed the PPUC's June 20, 2001 order in its entirety.  The
PPUC directed Met-Ed and Penelec to file tariffs within thirty days of the order
to reflect the CTC rates and  shopping  credits that were in effect prior to the
June 21, 2001 order to be effective  upon one day's notice.  In response to that
order,  Met-Ed and Penelec  filed these  supplements  to their tariffs to become
effective October 24, 2003.

          On  October  8,  2003,   Met-Ed  and  Penelec  filed  a  petition  for
clarification  relating to the October 2, 2003 order on two issues: to establish
June 30, 2004 as the date to fully refund the NUG trust fund and to clarify that
the ordered  accounting  treatment  regarding the CTC rate/shopping  credit swap
should  follow the  ratemaking,  and that the PPUC's  findings  would not impair
their rights to recover all of their stranded costs. On October 9, 2003,  ARIPPA
(an  intervenor  in the  proceedings)  petitioned  the PPUC to direct Met-Ed and
Penelec  to  reinstate   accounting  for  the  CTC  rate/shopping   credit  swap
retroactive to January 1, 2002.  Several other parties also filed petitions.  On
October 16,  2003,  the PPUC issued a  reconsideration  order  granting the date
requested  by Met-Ed and  Penelec  for the NUG trust fund  refund  and,  denying
Met-Ed's and  Penelec's  other  clarification  requests  and  granting  ARIPPA's
petition with respect to the retroactive  accounting treatment of the changes to
the CTC rate/shopping credit swap. On October 22, 2003, Met-Ed and Penelec filed
an  Objection  with the  Commonwealth  Court  asking that the Court  reverse the
PPUC's  finding that  requires  Met-Ed and Penelec to treat the  stipulated  CTC
rates that were in effect from January 1, 2002 on a retroactive basis.

          On October 27,  2003,  one  Commonwealth  Court judge  issued an Order
denying  Met-Ed's  and  Penelec's  objection  without  explanation.  Due  to the
vagueness  of the Order,  Met-Ed and  Penelec,  on October  31,  2003,  filed an
Application  for  Clarification  with the judge.  Concurrent  with this  filing,
Met-Ed and  Penelec,  in order to  preserve  their  rights,  also filed with the
Commonwealth  Court  both a Petition  for  Review of the  PPUC's  October 16 and
October 22 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.  In addition to these findings,  Met-Ed and
Penelec,  in compliance  with the PPUC's  Orders,  filed revised PPUC  quarterly
reports for the twelve  months  ended  December  31, 2001 and 2002,  and for the
first two  quarters  of 2003,  reflecting  balances  consistent  with the PPUC's
findings in their Orders.

          Effective  September 1, 2002,  Met-Ed and Penelec agreed to purchase a
portion  of their PLR  requirements  from FES  through a  wholesale  power  sale
agreement.  The PLR sale  will be  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 assumed 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. FES has hedged most of Met-Ed's
and  Penelec's  unfilled  PLR on-peak  obligation  through 2004 and a portion of
2005, the period during which deferred  accounting was previously  allowed under
the PPUC's  order.  Met-Ed and Penelec  are  authorized  to  continue  deferring
differences between NUG contract costs and current market prices.

                                       42

<PAGE>

          In late 2003,  the PPUC  issued a  Tentative  Order  implementing  new
reliability  benchmarks  and  standards.  In  connection  therewith,   the  PPUC
commenced a  rulemaking  procedure  to amend the  Electric  Service  Reliability
Regulations to implement these new benchmarks,  and create additional  reporting
on  reliability.  Although  neither  the  Tentative  Order  nor the  Reliability
Rulemaking has been finalized,  the PPUC ordered all  Pennsylvania  utilities to
begin filing quarterly  reports on November 1, 2003. The comment period for both
the Tentative Order and the Proposed Rulemaking Order has closed. FirstEnergy is
currently  awaiting the PPUC to issue a final order in both  matters.  The order
will  determine  (1) the standards  and  benchmarks to be utilized,  and (2) the
details required in the quarterly and annual reports.

          On January 16,  2004,  the PPUC  initiated a formal  investigation  of
whether  Met-Ed's,   Penelec's  and  Penn's  "service  reliability   performance
deteriorated  to a point  below the level of service  reliability  that  existed
prior  to  restructuring"  in  Pennsylvania.  Discovery  has  commenced  in  the
proceeding  and Met-Ed's,  Penelec's  and Penn's  testimony is due May 14, 2004.
Hearings are scheduled to begin August 3, 2004 in this investigation and the ALJ
has been  directed to issue a  Recommended  Decision by September  30, 2004,  in
order  to  allow  the  PPUC  time to  issue a Final  Order  by year end of 2004.
FirstEnergy is unable to predict the outcome of the  investigation or the impact
of the PPUC order.

       Davis-Besse Restoration

          On April 30, 2002,  the NRC initiated a formal  inspection  process at
the  Davis-Besse  nuclear plant.  This action was taken in response to corrosion
found by FENOC in the  reactor  vessel  head near the  nozzle  penetration  hole
during a  refueling  outage in the first  quarter  of 2002.  The  purpose of the
formal  inspection  process was to establish  criteria for NRC  oversight of the
licensee's  performance  and to  provide a record of the  major  regulatory  and
licensee actions taken,  and technical issues resolved.  This process led to the
NRC's March 8, 2004 approval of Davis-Besse's restart.

          Restart  activities  included both hardware and management  issues. In
addition  to  refurbishment  and  installation  work at the  plant,  FENOC  made
significant  management  and  human  performance  changes  with  the  intent  of
enhancing the proper  safety  culture  throughout  the  workforce.  The focus of
activities  in  the  first  quarter  of  2004  involved   management  and  human
performance issues. As a result,  incremental  maintenance costs declined in the
first quarter of 2004 compared to the same period in 2003 as emphasis shifted to
performance  issues;  however,  replacement power costs were higher in the first
quarter  of 2004.  The  plant's  generating  equipment  was  tested  in March in
preparation for resumption of operation.  On April 4, 2004,  Davis-Besse resumed
generating electricity at 100% power.

          Incremental costs associated with the extended  Davis-Besse outage for
the first quarter of 2004 and 2003 were as follows:

                                         Three Months Ended
                                              March 31,
                                        -------------------         Increase
Costs of Davis-Besse Extended Outage    2004           2003        (Decrease)
-----------------------------------------------------------------------------
                                                   (In millions)
Incremental Expense
  Replacement power.................     $64           $52           $ 12
  Maintenance.......................       1            36            (35)
--------------------------------------------------------------------------
      Total.........................     $65           $88           $(23)
==========================================================================

Incremental Net of Tax Expense......     $38           $52           $(14)
==========================================================================


       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  material  compliance  with  existing
regulations  but is unable to predict  future change in regulatory  policies and
what, if any, the effects of such change would be.

          The  EPA  has   proposed   the   Interstate   Air   Quality   Rule  to
"cap-and-trade"  NOx and SO2  emissions in two phases (Phase I in 2010 and Phase
II  in  2015).  According  to  the  EPA,  SO2  emissions  would  be  reduced  by
approximately  3.6 million tons in 2010, across states covered by the rule, with
reductions ultimately reaching more than 5.5 million tons annually. NOx emission
reductions  would measure about 1.5 million tons in 2010 and 1.8 million tons in
2015.  The future cost of  compliance  with these  proposed  regulations  may be
substantial  and will depend on whether and how they are ultimately  implemented
by the states in which the Companies operate affected facilities.

                                       43

<PAGE>

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

          In 1999 and 2000,  the EPA  issued  Notices  of  Violation  (NOV) or a
Compliance Order to nine utilities covering 44 power plants, including the W. H.
Sammis  Plant.  In addition,  the U.S.  Department  of Justice filed eight civil
complaints against various investor-owned utilities,  which included a complaint
against OE and Penn in the U.S.  District  Court for the  Southern  District  of
Ohio.  The NOV and  complaint  allege  violations  of the Clean Air Act based on
operation  and  maintenance  of the W. H. Sammis Plant dating back to 1984.  The
complaint  requests  permanent  injunctive relief to require the installation of
"best available control technology" and civil penalties of up to $27,500 per day
of  violation.  On August 7, 2003,  the  United  States  District  Court for the
Southern District of Ohio ruled that 11 projects  undertaken at the W. H. Sammis
Plant  between 1984 and 1998 required  pre-construction  permits under the Clean
Air Act. The ruling  concludes the liability phase of the case, which deals with
applicability of Prevention of Significant Deterioration provisions of the Clean
Air Act. The remedy  phase,  which is currently  scheduled to be ready for trial
beginning July 19, 2004, will address civil penalties and what, if any,  actions
should be taken to further  reduce  emissions at the plant.  In the ruling,  the
Court  indicated  that the remedies it "may consider and impose  involved a much
broader, equitable analysis, requiring the Court to consider air quality, public
health,  economic  impact,  and  employment  consequences.  The  Court  may also
consider  the less  than  consistent  efforts  of the EPA to apply  and  further
enforce the Clean Air Act." The potential penalties that may be imposed, as well
as the  capital  expenditures  necessary  to comply  with  substantive  remedial
measures  that  may  be  required,  could  have a  material  adverse  impact  on
FirstEnergy's  financial  condition  and results of  operations.  Management  is
unable to predict the ultimate  outcome of this matter and no liability has been
accrued as of March 31, 2004.

          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
U.S. Senate required for  ratification.  However,  the Bush  administration  has
committed the United  States to a voluntary  climate  change  strategy to reduce
domestic  greenhouse gas intensity - the ratio of emissions to economic output -
by 18% through  2012.  The  Companies  cannot  currently  estimate the financial
impact of climate change  policies  although the potential  restrictions  on CO2
emissions could require significant capital and other expenditures. However, the
CO2 emissions per  kilowatt-hour  of  electricity  generated by the Companies is
lower  than  many  regional  competitors  due  to  the  Companies'   diversified
generation  sources which includes low or non-CO2 emitting gas-fired and nuclear
generators.

       Power Outages

          In July 1999, the Mid-Atlantic  states experienced a severe heat storm
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 New Jersey  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.

          Since July 1999, this litigation has involved a substantial  amount of
legal discovery including interrogatories,  request for production of documents,
preservation and inspection of evidence, and depositions of the named plaintiffs
and many JCP&L  employees.  In addition,  there have been many motions filed and
argued by the parties  involving  issues such as the  primary  jurisdiction  and
findings of the NJBPU, consumer fraud by JCP&L, strict product liability,  class
decertification, and the damages claimed by the plaintiffs. In January 2000, the
NJ Appellate  Division  determined that the trial court has proper  jurisdiction
over this  litigation.  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 products 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 have been appealed to the Appellation  Division and oral argument
is scheduled for May 2004. FirstEnergy is unable to predict the outcome of these
matters and no liability  has been  accrued as of March 31, 2004.

                                       44

<PAGE>

          On August  14,  2003,  various  states  and parts of  southern  Canada
experienced a widespread power outage.  That outage affected  approximately  1.4
million  customers in  FirstEnergy's  service area.  On April 5, 2004,  the U.S.
-Canada Power System Outage Task Force released its final report on this outage.
The final report supercedes the interim report that had been issued in November,
2003. In the final report,  the Task Force concluded,  among other things,  that
the problems  leading to the outage began in  FirstEnergy's  Ohio service  area.
Specifically,   the  final  report  concludes,  among  other  things,  that  the
initiation of the August 14th power outage resulted from the coincidence on that
afternoon of several events,  including,  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 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 14th power outage and that it does not
adequately  address the  underlying  causes of the outage.  FirstEnergy  remains
convinced  that the outage  cannot be explained  by events on any one  utility's
system. The final report contains 46 "recommendations to prevent or minimize the
scope of future blackouts."  Forty-five of those recommendations relate to broad
industry  or policy  matters  while one  relates  to  activities  the Task Force
recommends be undertaken by FirstEnergy,  MISO,  PJM, and ECAR.  FirstEnergy has
undertaken  several  initiatives,  some prior to and some since the August  14th
power outage,  to enhance  reliability which are consistent with these and other
recommendations  and believes it will complete  those relating to summer 2004 by
June 30 (see Regulatory  Matters above).  As many of these  initiatives  already
were in process and  budgeted  in 2004,  FirstEnergy  does not believe  that any
incremental  expenses associated with additional  initiatives  undertaken during
2004 will  have a  material  effect  on its  operations  or  financial  results.
FirstEnergy  notes,   however,  that  the  applicable  government  agencies  and
reliability   coordinators   may  take  a  different   view  as  to  recommended
enhancements or may recommend  additional  enhancements in the future that could
require additional, material expenditures.

       Davis-Besse

          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
plant.  FirstEnergy is unable to predict the outcome of this  investigation.  In
addition,  FENOC remains subject to possible civil enforcement action by the NRC
in  connection  with the  events  leading  to the  Davis-Besse  outage  in 2002.
Further,  a  petition  was  filed  with  the NRC on  March  29,  2004 by a group
objecting to the NRC's restart order of the  Davis-Besse  Nuclear Power Station.
The Petition seeks, among other things,  suspension of the Davis-Besse operating
license.  If it were ultimately  determined that FirstEnergy has legal liability
or is  otherwise  made subject to  enforcement  action based on any of the above
matters with respect to the Davis-Besse outage, it could have a material adverse
effect on FirstEnergy's financial condition and results of operations.

       Other Legal Matters

          Various  lawsuits,  claims and  proceedings  related to  FirstEnergy's
normal business operations are pending against FirstEnergy and its subsidiaries.
The most significant not otherwise discussed above are described below.

          Legal  proceedings  have been filed against  FirstEnergy in connection
with,  among other things,  the  restatements in August 2003, by FirstEnergy and
its Ohio utility  subsidiaries of previously  reported results,  the August 14th
power outage described above, and the extended outage at the Davis-Besse Nuclear
Power  Station.  Depending  upon the  particular  proceeding,  the issues raised
include alleged  violations of federal  securities  laws,  breaches of fiduciary
duties under state law by FirstEnergy  directors and officers,  and damages as a
result  of one or more of the  noted  events.  The  securities  cases  have been
consolidated  into one action pending in federal court in Akron.  The derivative
actions filed in federal court  likewise  have been  consolidated  as a separate
matter,  also in  federal  court in Akron.  There  also are  pending  derivative
actions in state court.

          FirstEnergy's Ohio utility subsidiaries were also named as respondents
in two  regulatory  proceedings  initiated at the PUCO in response to complaints
alleging failure to provide  reasonable and adequate service stemming  primarily
from the August 14th power outage.  FirstEnergy  is vigorously  defending  these
actions,  but cannot predict the outcome of any of these  proceedings or whether
any further  regulatory  proceedings or legal actions may be instituted  against
them. In particular,  if FirstEnergy  were  ultimately  determined to have legal
liability in connection with these proceedings, it could have a material adverse
effect on its financial condition and results of operations.

          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  outage.  All three cases were
dismissed  for lack of  jurisdiction.  One case was  refiled at the PUCO and the
other two have been appealed.

                                       45

<PAGE>

CRITICAL ACCOUNTING POLICIES

          FirstEnergy   prepares  its  consolidated   financial   statements  in
accordance  with GAAP.  Application  of these  principles  often requires a high
degree of judgment, estimates and assumptions that affect financial results. All
of   FirstEnergy's   assets  are  subject  to  their  own  specific   risks  and
uncertainties and are regularly  reviewed for impairment.  Assets related to the
application of the policies  discussed  below are similarly  reviewed with their
risks and uncertainties  reflecting these specific factors.  FirstEnergy's  more
significant accounting policies are described below.

       Regulatory Accounting

          FirstEnergy's regulated services segment is subject to regulation that
sets the prices  (rates) it is permitted to charge its customers  based on costs
that the regulatory  agencies determine  FirstEnergy is permitted to recover. At
times,  regulators  permit the future recovery through rates of costs that would
be currently  charged to expense by an  unregulated  company.  This  rate-making
process  results in the  recording of  regulatory  assets  based on  anticipated
future cash inflows.  As a result of the changing  regulatory  framework in each
state in which FirstEnergy  operates,  a significant amount of regulatory assets
have been  recorded - $6.7 billion as of March 31, 2004.  FirstEnergy  regularly
reviews these assets to assess their ultimate recoverability within the approved
regulatory  guidelines.  Impairment risk associated with these assets relates to
potentially adverse legislative, judicial or regulatory actions in the future.

       Derivative Accounting

          Determination  of appropriate  accounting for derivative  transactions
requires the involvement of management representing operations, finance and risk
assessment.  In order to determine the  appropriate  accounting  for  derivative
transactions,  the  provisions of the contract need to be carefully  assessed in
accordance  with  the  authoritative   accounting  literature  and  management's
intended use of the derivative.  New authoritative  guidance  continues to shape
the  application  of  derivative  accounting.   Management's   expectations  and
intentions  are key factors in  determining  the  appropriate  accounting  for a
derivative  transaction and, as a result,  such  expectations and intentions are
documented. Derivative contracts that are determined to fall within the scope of
SFAS 133, as amended, must be recorded at their fair value. Active market prices
are not always  available  to  determine  the fair value of the later years of a
contract,  requiring  that various  assumptions  and  estimates be used in their
valuation.   FirstEnergy   continually  monitors  its  derivative  contracts  to
determine if its activities, expectations, intentions, assumptions and estimates
remain  valid.  As part of its  normal  operations,  FirstEnergy  enters  into a
significant number of commodity contracts, as well as interest rate swaps, which
increase the impact of derivative accounting judgments.

       Revenue Recognition

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

       Pension and Other Postretirement Benefits Accounting

          FirstEnergy's  reported  costs of providing  non-contributory  defined
pension benefits and  postemployment  benefits other than pensions are dependent
upon  numerous  factors  resulting  from  actual  plan  experience  and  certain
assumptions.

          Pension  and  OPEB  costs  are   affected  by  employee   demographics
(including  age,  compensation  levels,  and employment  periods),  the level of
contributions  FirstEnergy makes to the plans, and earnings on plan assets. Such
factors may be further affected by business  combinations (such as FirstEnergy's
merger with GPU in November 2001),  which impacts  employee  demographics,  plan
experience  and other  factors.  Pension  and OPEB  costs are also  affected  by
changes  to key  assumptions,  including  anticipated  rates of  return  on plan
assets,  the discount rates and health care trend rates used in determining  the
projected benefit obligations for pension and OPEB costs.

          In accordance  with SFAS 87 and SFAS 106,  changes in pension and OPEB
obligations  associated with these factors may not be immediately  recognized as
costs on the income statement, but generally are recognized in future years over
the remaining average service period of plan participants.  SFAS 87 and SFAS 106
delay  recognition  of changes due to the  long-term  nature of pension and OPEB
obligations and the varying market  conditions likely to occur over long periods
of time. As such, significant portions of pension and OPEB costs recorded in any
period  may not  reflect  the actual  level of cash  benefits  provided  to plan
participants and are significantly influenced by assumptions about future market
conditions and plan participants' experience.

                                       46

<PAGE>

          In selecting an assumed discount rate, FirstEnergy considers currently
available rates of return on high-quality fixed income  investments  expected to
be   available   during  the  period  to  maturity  of  the  pension  and  other
postretirement  benefit  obligations.  Due to recent  declines in corporate bond
yields and interest rates in general,  FirstEnergy  reduced the assumed discount
rate as of December 31, 2003 to 6.25% from 6.75% used as of December 31, 2002.

          FirstEnergy's  assumed rate of return on pension plan assets considers
historical  market  returns and economic  forecasts for the types of investments
held by its pension trusts.  In 2003 and 2002, plan assets actually earned 24.0%
and (11.3)%,  respectively.  FirstEnergy's  pension  costs in 2003 and the first
quarter  of 2004 were  computed  assuming  a 9.0% rate of return on plan  assets
based upon  projections  of future  returns  and its  pension  trust  investment
allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash.

          Based on pension  assumptions  and pension  plan assets as of December
31, 2003,  FirstEnergy  will not be required to fund its pension  plans in 2004.
However,  health care cost trends have  significantly  increased and will affect
future  OPEB  costs.  The  2004  and  2003  composite  health  care  trend  rate
assumptions are approximately 10%-12% gradually decreasing to 5% in later years.
In determining  its trend rate  assumptions,  FirstEnergy  included the specific
provisions of its health care plans, the  demographics and utilization  rates of
plan participants,  actual cost increases  experienced in its health care plans,
and projections of future medical trend rates.

       Ohio Transition Cost Amortization

          In connection with FirstEnergy's  transition plan, the PUCO determined
allowable  transition costs based on amounts recorded on the regulatory books of
the Ohio electric utilities.  These costs exceeded those deferred or capitalized
on  FirstEnergy's  balance sheet prepared under GAAP since they included certain
costs which have not yet been incurred or that were recognized on the regulatory
financial statements (fair value purchase accounting  adjustments).  FirstEnergy
uses an effective  interest  method for amortizing its transition  costs,  often
referred to as a  "mortgage-style"  amortization.  The interest  rate under this
method is equal to the rate of return  authorized by the PUCO in the  transition
plan for each respective company. In computing the transition cost amortization,
FirstEnergy includes only the portion of the transition revenues associated with
transition  costs included on the balance sheet  prepared  under GAAP.  Revenues
collected for the off balance sheet costs and the return  associated  with these
costs are recognized as income when received.

       Long-Lived Assets

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

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

       Nuclear Decommissioning

          In  accordance  with SFAS 143,  FirstEnergy  recognizes an ARO for the
future decommissioning of its nuclear power plants. The ARO liability represents
an estimate of the fair value of  FirstEnergy's  current  obligation  related to
nuclear  decommissioning  and the  retirement  of  other  assets.  A fair  value
measurement  inherently  involves  uncertainty  in  the  amount  and  timing  of
settlement of the liability. FirstEnergy used an expected cash flow approach (as
discussed in FASB  Concepts  Statement No. 7, "Using Cash Flow  Information  and
Present  Value in  Accounting  Measurements")  to measure  the fair value of the
nuclear  decommissioning  ARO. This approach  applies  probability  weighting to
discounted future cash flow scenarios that reflect a range of possible outcomes.
The scenarios  consider  settlement of the ARO at the  expiration of the nuclear
power plants' current license and settlement based on an extended license term.

       Goodwill

          In a business  combination,  the excess of the purchase price over the
estimated  fair  values  of the  assets  acquired  and  liabilities  assumed  is
recognized as goodwill.  Based on the guidance provided by SFAS 142, FirstEnergy
evaluates  goodwill  for  impairment  at least  annually  and would make such an
evaluation  more  frequently  if  indicators  of  impairment  should  arise.  In
accordance with the accounting  standard,  if the fair value of a reporting unit
is less than its carrying value (including goodwill), the goodwill is tested for
impairment.  If an  impairment  is  indicated  FirstEnergy  recognizes  a loss -
calculated  as the  difference  between  the  implied  fair value of a reporting

                                       47

<PAGE>

unit's  goodwill and the carrying  value of the goodwill.  FirstEnergy's  annual
review was completed in the third quarter of 2003. As a result of that review, a
non-cash goodwill  impairment charge of $122 million was recognized in the third
quarter of 2003,  reducing the  carrying  value of FSG.  The  forecasts  used in
FirstEnergy's  evaluations of goodwill  reflect  operations  consistent with its
general business  assumptions.  Unanticipated changes in those assumptions could
have a significant effect on FirstEnergy's future evaluations of goodwill. As of
March 31, 2004,  FirstEnergy had $6.1 billion of goodwill that primarily relates
to its regulated services segment.

NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

       EITF Issue No. 03-6,  "Participating  Securities and the Two-Class Method
       Under Financial  Accounting  Standards Board Statement No. 128,  Earnings
       per Share"

          On March 31, 2004, the FASB ratified the consensus reached by the EITF
on  Issue  03-6.  The  issue  addresses  a number  of  questions  regarding  the
computation of earnings per share by companies that have issued securities other
than  common  stock that  contractually  entitle  the holder to  participate  in
dividends and earnings of a company when,  and if, it declares  dividends on its
common stock. The issue also provides further guidance in applying the two-class
method of computing  earnings per share once it is determined that a security is
participating,  including  how to  allocate  undistributed  earnings  to  such a
security.  EITF 03-06 is effective for fiscal periods  beginning after March 31,
2004. FirstEnergy is currently evaluating the effect of adopting EITF 03-6.

       FSP  106-1,  "Accounting  and  Disclosure  Requirements  Related  to  the
       Medicare Prescription Drug, Improvement and Modernization Act of 2003"

          Issued   January  12,  2004,   FSP  106-1   permits  a  sponsor  of  a
postretirement  health care plan that  provides a  prescription  drug benefit to
make a one-time  election to defer  accounting  for the effects of the  Medicare
Act.  FirstEnergy  elected to defer the effects of the  Medicare  Act due to the
lack of specific guidance.  Pursuant to FSP 106-1,  FirstEnergy began accounting
for the effects of the Medicare Act  effective  January 1, 2004 as a result of a
February  2, 2004 plan  amendment  that  required  remeasurement  of the  plan's
obligations.  See Note 2 for a discussion  of the effect of the federal  subsidy
and plan amendment on the consolidated financial statements.

       FIN 46 (revised  December  2003),  "Consolidation  of  Variable  Interest
       Entities"

          In  December  2003,  the  FASB  issued  a  revised  interpretation  of
Accounting  Research  Bulletin  No.  51,  "Consolidated  Financial  Statements",
referred  to as  FIN  46R,  which  requires  the  consolidation  of a VIE  by an
enterprise if that enterprise is determined to be the primary beneficiary of the
VIE. As required,  FirstEnergy  adopted FIN 46R for  interests in VIEs  commonly
referred to as special-purpose  entities effective December 31, 2003 and for all
other types of entities  effective  March 31, 2004.  Adoption of FIN 46R did not
have a material  impact on  FirstEnergy's  financial  statements for the quarter
ended March 31, 2004.

          For the quarter  ended March 31, 2004,  FirstEnergy  evaluated,  among
other entities, its power purchase agreements and determined that it is possible
that  nine  NUG  entities  might  be  considered   variable  interest  entities.
FirstEnergy  has  requested  but  not  received  the  information  necessary  to
determine whether these entities are VIEs or whether JCP&L, Met-Ed or Penelec is
the primary beneficiary.  In most cases, the requested information was deemed to
be competitive  and  proprietary  data. 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 2004 and 2003 were
$51 million (JCP&L - $28 million, Met-Ed - $16 million and Penelec - $7 million)
and $56  million  (JCP&L - $34  million,  Met-Ed - $15  million and Penelec - $7
million),  respectively.  FirstEnergy is required to continue to make exhaustive
efforts to obtain the necessary  information  in future periods and is unable to
determine  the possible  impact of  consolidating  any such entity  without this
information.

       EITF Issue No. 03-11,  "Reporting Realized Gains and Losses on Derivative
       Instruments  That Are Subject to SFAS No. 133,  Accounting for Derivative
       Instruments and Hedging  Activities,  and Not "Held for Trading Purposes"
       as  Defined in EITF Issue  02-03,  "Issues  Involved  in  Accounting  for
       Derivative  Contracts Held for Trading Purposes and Contracts Involved in
       Energy Trading and Risk Management Activities."

          In July 2003,  the EITF reached a consensus that  determining  whether
realized gains and losses on physically settled  derivative  contracts not "held
for trading  purposes"  should be reported in the income statement on a gross or
net  basis is a matter  of  judgment  that  depends  on the  relevant  facts and
circumstances.  The  consideration  of the  facts and  circumstances,  including
economic  substance,  should be made in the context of the various activities of
the entity  rather than based solely on the terms of the  individual  contracts.
The  adoption  of this  consensus  effective  January  1,  2004,  did not have a
material impact on the Companies' financial statements.

                                       48

<PAGE>

<TABLE>


                                              OHIO EDISON COMPANY

                                       CONSOLIDATED STATEMENTS OF INCOME
                                                  (Unaudited)


<CAPTION>
                                                                                          Three Months Ended
                                                                                                March 31,
                                                                                       -------------------------
                                                                                         2004             2003
                                                                                       --------         --------
                                                                                             (In thousands)

<S>                                                                                    <C>              <C>
OPERATING REVENUES..............................................................       $743,295         $742,743
                                                                                       --------         --------

OPERATING EXPENSES AND TAXES:
   Fuel.........................................................................         15,070           12,850
   Purchased power..............................................................        249,881          243,828
   Nuclear operating costs......................................................         79,641          125,368
   Other operating costs........................................................         81,474           90,273
                                                                                       --------         --------
     Total operation and maintenance expenses...................................        426,066          472,319
   Provision for depreciation and amortization..................................        124,729          108,385
   General taxes................................................................         48,566           48,256
   Income taxes.................................................................         61,574           43,701
                                                                                       --------         --------
     Total operating expenses and taxes.........................................        660,935          672,661
                                                                                       --------         --------

OPERATING INCOME................................................................         82,360           70,082

OTHER INCOME....................................................................         12,471           13,501
                                                                                       --------         --------

INCOME BEFORE NET INTEREST CHARGES..............................................         94,831           83,583
                                                                                       --------         --------

NET INTEREST CHARGES:
   Interest on long-term debt...................................................         16,589           24,488
   Allowance for borrowed funds used during construction and capitalized interest        (1,381)          (1,380)
   Other interest expense.......................................................          2,890            2,478
   Subsidiaries' preferred stock dividend requirements..........................            640              912
                                                                                       --------         --------
     Net interest charges.......................................................         18,738           26,498
                                                                                       --------         --------

INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE............................         76,093           57,085

Cumulative effect of accounting change (net of income taxes of $22,389,000) (Note 2)         --           31,720
                                                                                        -------         --------

NET INCOME......................................................................         76,093           88,805

PREFERRED STOCK DIVIDEND REQUIREMENTS...........................................            561              659
                                                                                       --------         --------

EARNINGS ON COMMON STOCK........................................................       $ 75,532         $ 88,146
                                                                                       ========         ========


<FN>
The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral
part of these statements.

</FN>

                                                     49
</TABLE>

<PAGE>

<TABLE>

                                              OHIO EDISON COMPANY

                                          CONSOLIDATED BALANCE SHEETS
                                                  (Unaudited)
<CAPTION>

                                                                                        March 31,       December 31,
                                                                                          2004              2003
                                                                                       ----------       -----------
                                                                                            (In thousands)
                                        ASSETS
UTILITY PLANT:
<S>                                                                                   <C>               <C>
   In service......................................................................   $5,304,122        $5,269,042
   Less-Accumulated provision for depreciation.....................................    2,611,122         2,578,899
                                                                                      ----------        ----------
                                                                                       2,693,000         2,690,143
                                                                                      ----------        ----------
   Construction work in progress-
     Electric plant................................................................      143,478           145,380
     Nuclear Fuel..................................................................          554               554
                                                                                      ----------        ----------
                                                                                         144,032           145,934
                                                                                      ----------        ----------
                                                                                       2,837,032         2,836,077
                                                                                      ----------        ----------
OTHER PROPERTY AND INVESTMENTS:
   Investment in lease obligation bonds............................................      383,088           383,510
   Letter of credit collateralization..............................................           --           277,763
   Nuclear plant decommissioning trusts............................................      394,705           376,367
   Long-term notes receivable from associated companies ...........................      209,271           508,594
   Other...........................................................................       56,131            59,102
                                                                                      ----------        ----------
                                                                                       1,043,195         1,605,336
                                                                                      ----------        ----------
CURRENT ASSETS:
   Cash and cash equivalents.......................................................        1,323             1,883
   Receivables-
     Customers (less accumulated provisions of $8,714,000 and $8,747,000,
       respectively, for uncollectible accounts)...................................      267,315           280,538
     Associated companies..........................................................      500,570           436,991
     Other (less accumulated provisions of $1,724,000 and $2,282,000
       for uncollectible accounts).................................................       29,887            28,308
   Letter of credit collateralization..............................................      277,763                --
   Notes receivable from associated companies......................................      616,912           366,501
   Materials and supplies, at average cost.........................................       82,575            79,813
   Prepayments and other...........................................................       26,219            14,390
                                                                                      ----------        ----------
                                                                                       1,802,564         1,208,424
                                                                                      ----------        ----------
DEFERRED CHARGES:
   Regulatory assets...............................................................    1,363,242         1,477,969
   Property taxes..................................................................       59,279            59,279
   Unamortized sale and leaseback costs............................................       64,284            65,631
   Other...........................................................................       64,353            64,214
                                                                                      ----------        ----------
                                                                                       1,551,158         1,667,093
                                                                                      ----------        ----------
                                                                                      $7,233,949        $7,316,930
                                                                                      ==========        ==========

                           CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
   Common stockholder's equity-
     Common stock, without par value, authorized 175,000,000
       shares - 100 shares outstanding.............................................   $2,098,729        $2,098,729
     Accumulated other comprehensive loss..........................................      (35,657)          (38,693)
     Retained earnings.............................................................      544,466           522,934
                                                                                      ----------        ----------
       Total common stockholder's equity...........................................    2,607,538         2,582,970
   Preferred stock not subject to mandatory redemption.............................       60,965            60,965
   Preferred stock of consolidated subsidiary not subject to mandatory redemption..       39,105            39,105
   Long-term debt and other long-term obligations..................................    1,160,452         1,179,789
                                                                                      ----------        ----------
                                                                                       3,868,060         3,862,829
                                                                                      ----------        ----------
CURRENT LIABILITIES:
   Currently payable long-term debt and preferred stock............................      428,438           466,589
   Short-term borrowings-
     Associated companies..........................................................       67,849            11,334
     Other.........................................................................      131,367           171,540
   Accounts payable-
     Associated companies..........................................................      512,386           271,262
     Other.........................................................................        7,834             7,979
   Accrued taxes...................................................................      248,768           560,345
   Accrued interest................................................................       24,157            18,714
   Other...........................................................................       99,116            58,680
                                                                                      ----------        ----------
                                                                                       1,519,915         1,566,443
                                                                                      ----------        ----------
NONCURRENT LIABILITIES:
   Accumulated deferred income taxes...............................................      824,832           867,691
   Accumulated deferred investment tax credits.....................................       72,664            75,820
   Asset retirement obligation.....................................................      322,929           317,702
   Retirement benefits.............................................................      342,952           331,829
   Other...........................................................................      282,597           294,616
                                                                                      ----------        ----------
                                                                                       1,845,974         1,887,658
                                                                                      ----------        ----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 3).................................
                                                                                      ----------        ----------
                                                                                      $7,233,949        $7,316,930
                                                                                      ==========        ==========

<FN>
The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral
part of these balance sheets.
</FN>

                                                      50

</TABLE>

<PAGE>

<TABLE>

                                              OHIO EDISON COMPANY

                                     CONSOLIDATED STATEMENTS OF CASH FLOWS
                                                  (Unaudited)

<CAPTION>
                                                                                          Three Months Ended
                                                                                                March 31,
                                                                                      ----------------------------
                                                                                        2004               2003
                                                                                      ---------          ---------
                                                                                             (In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
<S>                                                                                   <C>                <C>
Net income......................................................................      $  76,093          $  88,805
   Adjustments to reconcile net income to net cash from operating activities-
     Provision for depreciation and amortization................................        124,729            108,385
     Nuclear fuel and lease amortization........................................         11,261              7,106
     Deferred income taxes, net.................................................        (26,387)             7,683
     Investment tax credits, net................................................         (3,658)            (3,704)
     Cumulative effect of accounting change (Note 2)............................             --            (54,109)
     Receivables................................................................        (51,935)           (29,909)
     Materials and supplies.....................................................         (2,762)            (1,298)
     Accounts payable...........................................................        240,979             14,470
     Accrued taxes..............................................................       (311,577)             6,051
     Accrued interest...........................................................          5,443              2,437
     Deferred lease costs.......................................................         33,030             31,683
     Prepayments and other current assets ......................................        (11,829)           (14,893)
     Accrued retirement benefit obligations.....................................         11,123              2,679
     Accrued compensation, net..................................................          4,404             (5,802)
     Other......................................................................         16,562             (6,067)
                                                                                      ---------          ---------
       Net cash provided from operating activities..............................        115,476            153,517
                                                                                      ---------          ---------

CASH FLOWS FROM FINANCING ACTIVITIES:
   New Financing-
     Long-term debt.............................................................         30,000                 --
     Short-term borrowings, net.................................................         16,341                 --
   Redemptions and Repayments-
     Long-term debt.............................................................        (97,001)           (19,493)
     Short-term borrowings, net.................................................             --           (232,278)
   Dividend Payments-
     Common stock...............................................................        (54,000)           (13,000)
     Preferred stock............................................................           (561)              (659)
                                                                                      ---------          ---------
       Net cash used for financing activities...................................       (105,221)          (265,430)
                                                                                      ---------          ---------

CASH FLOWS FROM INVESTING ACTIVITIES:
   Property additions...........................................................        (37,661)           (68,367)
   Contributions to nuclear decommissioning trusts..............................         (7,885)            (7,885)
   Nuclear decommissioning trust investments....................................        (10,453)             4,777
   Associated company loan activities, net......................................         48,912            173,250
   Other........................................................................         (3,728)             3,946
                                                                                      ---------          ---------
       Net cash provided from (used for) investing activities...................        (10,815)           105,721
                                                                                      ---------          ---------

Net decrease in cash and cash equivalents.......................................           (560)            (6,192)
Cash and cash equivalents at beginning of period................................          1,883             20,512
                                                                                      ---------          ---------
Cash and cash equivalents at end of period......................................      $   1,323          $  14,320
                                                                                      =========          =========

<FN>
The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral
part of these statements.
</FN>

                                                      51

</TABLE>

<PAGE>


                        REPORT OF INDEPENDENT ACCOUNTANTS


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, 2004, and the related  consolidated
statements  of income and cash flows for each of the  three-month  periods ended
March  31,  2004  and  2003.   These  interim   financial   statements  are  the
responsibility of the Company's management.

We conducted our review in accordance with standards established by the American
Institute  of  Certified  Public  Accountants.  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 generally
accepted  auditing  standards,  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 auditing  standards  generally accepted
in the  United  States  of  America,  the  consolidated  balance  sheet  and the
consolidated  statement  of  capitalization  as of December  31,  2003,  and the
related  consolidated   statements  of  income,   common  stockholder's  equity,
preferred  stock,  cash flows and taxes for the year then  ended (not  presented
herein),  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 1(F) 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 February 25, 2004, we expressed
an  unqualified  opinion  on those  consolidated  financial  statements.  In our
opinion,  the information set forth in the accompanying  condensed  consolidated
balance sheet as of December 31, 2003, 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 7, 2004

                                       52

<PAGE>


                               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. OE and Penn
(OE Companies) also provide  generation  services to those customers electing to
retain them as their power supplier.  The OE Companies provide power directly to
wholesale  customers  under  previously  negotiated  contracts,  as  well  as to
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 2004 decreased to $76
million from $88 million in the first quarter of 2003.  Earnings on common stock
in the first  quarter of 2003  included an after-tax  credit of $32 million from
the cumulative  effect of an accounting  change due to the adoption of SFAS 143.
Income before the cumulative effect was $76 million in the first three months of
2004,  compared to $57 million for the same period of 2003.  Improved results in
the first quarter of 2004 reflect lower operating  expenses - primarily  nuclear
operating costs, and reduced  financing costs compared with the first quarter of
2003.  Partially  offsetting  these  improvements  were higher  nuclear fuel and
purchased power costs and increased amortization of regulatory assets.

          Operating  revenues  increased  by $0.6  million  or 0.1% in the first
quarter of 2004  compared  with the same  period in 2003.  The  higher  revenues
primarily resulted from additional sales to FES which were substantially  offset
by lower  generation  retail sales to residential  and commercial  customers and
reduced revenue from  distribution  throughput.  Total retail electric  revenues
decreased  by $7 million  in the first  quarter  of 2004  compared  to the first
quarter of 2003 reflecting reduced consumption due principally to milder weather
and a continued  sluggish  economy in our service area ($13  million)  partially
offset by higher  composite  prices from a change in customer sales by class ($6
million).

          Kilowatt-hour  sales to retail customers declined by 3.3% in the first
quarter of 2004 compared to the same quarter of 2003,  which reduced  generation
sales  revenue  by $2  million.  The  decline  reflected  the  increase  of  2.3
percentage  points in  electric  generation  services  provided  by  alternative
suppliers as a percent of total sales  delivered in OE's  franchise area in 2004
from the first quarter of 2003. In addition,  distribution  deliveries decreased
by 1.6% in the first  quarter of 2004  compared  with the first quarter of 2003,
with declines in all customer sectors (residential, commercial and industrial).

          Sales  revenues from wholesale  customers  increased by $10 million in
the first  quarter of 2004  compared  to the same  period of 2003,  due to a 23%
increase in nuclear  generation  available for sale to FES  partially  offset by
lower composite prices. The increased  generation was due to the absence in 2004
of the Beaver Valley Unit 1 refueling outage in 2003.

          Changes in electric  generation sales and  distribution  deliveries in
the first  quarter of 2004 from the same quarter of 2003 are  summarized  in the
following table:


                  Changes in Kilowatt-Hour Sale
                  ---------------------------------------------------
                  Increase (Decrease)
                  Electric Generation:
                    Retail..................................    (3.3)%
                    Wholesale...............................     9.1%
                  ---------------------------------------------------
                  Total Electric Generation Sales...........     2.2%
                  ===================================================
                  Distribution Deliveries:
                    Residential.............................    (2.1)%
                    Commercial..............................    (0.6)%
                    Industrial..............................    (1.8)%
                  ----------------------------------------------------
                  Total Distribution Deliveries.............    (1.6)%
                  ====================================================

                                       53

<PAGE>


       Operating Expenses and Taxes

          Total  operating  expenses  and taxes  decreased by $12 million in the
first  quarter  of 2004 from the first  quarter  of 2003.  The  following  table
presents changes from the prior year by expense category.

          Operating Expenses and Taxes - Changes
          -----------------------------------------------------------------
           Increase (Decrease)                                 (In millions)
          Fuel.............................................       $  2
          Purchased power .................................          6
          Nuclear operating costs..........................        (45)
          Other operating costs............................         (9)
          -------------------------------------------------------------
            Total operation and maintenance expenses.......        (46)

          Provision for depreciation and amortization......         16
          General taxes....................................         --
          Income taxes.....................................         18
          ------------------------------------------------------------
            Total operating expenses and taxes.............       $(12)
          =============================================================


          Higher fuel costs in the first quarter of 2004, compared with the same
quarter of 2003,  resulted from increased  nuclear  generation - 23%.  Purchased
power  costs  increased  by $6 million  reflecting  higher unit costs which were
partially  offset  by  lower  kilowatt-hour   purchases  due  to  the  decreased
requirements for retail generation sales. Lower nuclear operating costs occurred
in large part due to the absence of the Beaver  Valley  Unit 1 (100%  ownership)
outage  that  occurred  in the first  quarter  of 2003.  The  decrease  in other
operating costs reflects in part lower employee benefit costs.

          Charges for depreciation and amortization  increased by $16 million in
the first quarter of 2004 compared to the first quarter of 2003  primarily  from
two factors - increased  amortization of the Ohio transition  regulatory  assets
($14 million) and lower  shopping  incentive  deferrals ($1 million),  partially
offset by increased regulatory asset deferrals of $2 million.

       Net Interest Charges

          Net  interest  charges  continued  to trend  lower,  decreasing  by $8
million in the first quarter of 2004 from the same period last year,  reflecting
redemptions and refinancings  since the first quarter of 2003. OE Companies' net
debt  redemptions  totaled $55 million  during the first quarter of 2004 and are
expected  to result in  annualized  savings of $4 million  (excluding  change in
revolver facilities).

       Cumulative Effect of Accounting Change

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

Capital Resources and Liquidity
-------------------------------

          OE's cash  requirements in 2004 for operating  expenses,  construction
expenditures,  scheduled debt  maturities and preferred  stock  redemptions  are
expected  to be  met  without  increasing  its  net  debt  and  preferred  stock
outstanding.  Available  borrowing  capacity under short-term  credit facilities
will be used to manage working capital requirements.  Over the next three years,
OE  expects  to meet its  contractual  obligations  with cash  from  operations.
Thereafter,  OE expects to use a combination  of cash from  operations and funds
from the capital markets.

       Changes in Cash Position

          As of March 31, 2004, OE had $1 million of cash and cash  equivalents,
compared with $2 million as of December 31, 2003.  The major sources for changes
in these balances are summarized below.

       Cash Flows From Operating Activities

          Cash  provided by  operating  activities  during the first  quarter of
2004, compared with the corresponding period in 2003 were as follows:

                                       54

<PAGE>


               Operating Cash Flows                     2004          2003
               -------------------------------------------------------------
                                                           (In millions)

               Cash earnings (1)....................     $230         $183
               Working capital and other............     (115)         (29)
               -------------------------------------------------------------

               Total................................     $115         $154
               =============================================================

          (1) Includes net income, depreciation and amortization, deferred
              income  taxes,  investment  tax  credits  and major  noncash
              charges.


          Net cash from operating activities decreased $39 million due to an $86
million  increase in funds used for working  capital -- that decrease was offset
in part by a $47 million  increase in cash  earnings.  The decrease from working
capital and other changes primarily reflects the change in cash requirements for
accounts  payable to  associated  companies of $227 million and accrued taxes of
$318 million for the first quarter of 2004 as compared to 2003.  Both  variances
reflect  offsetting  changes  of  $249  million  for  the  reallocation  of  tax
liabilities between associated companies related to the tax sharing agreement.

       Cash Flows From Financing Activities

          In the first quarter of 2004,  net cash used for financing  activities
decreased to $105  million  from $265 million in the same period last year.  The
decrease resulted from increased  short-term  borrowings  partially offset by an
increase in common stock dividend payments to FirstEnergy.

          OE had  approximately  $618 million of cash and temporary  investments
(which  include  short-term  notes  receivable  from  associated  companies) and
approximately  $199  million of  short-term  indebtedness  as of March 31, 2004.
Available  borrowing  capability  under bilateral bank  facilities  totaled $159
million as of March 31, 2004.  The OE Companies had the capability to issue $2.1
billion  of  additional  first  mortgage  bonds  (FMB) on the basis of  property
additions and retired bonds,  although  unsecured senior note indentures entered
into by OE in 2003  limit its  ability  to issue  secured  debt, including  FMB,
subject to certain exceptions. Based upon applicable earnings coverage tests the
OE  Companies  could issue up to $3.4 billion of  preferred  stock  (assuming no
additional debt was issued) as of March 31, 2004.

          In October  2003,  OE entered into a syndicated  $125 million  364-day
revolving  credit  facility and a syndicated $125 million  three-year  revolving
credit  facility.  Combined with an existing  syndicated  $250 million  two-year
facility for OE, maturing in May 2005 and bank  facilities of $34 million,  OE's
available credit  facilities total $534 million,  all of which were unused as of
March 31, 2004. These  facilities are intended to provide  liquidity to meet the
short-term working capital requirements of OE and its affiliates.

          Borrowings  under these  facilities are  conditioned on OE maintaining
compliance with certain  financial  covenants in the  agreements.  OE, under its
$125  million  364-day  and $250  million  two-year  facilities,  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. OE is
in  compliance  with these  financial  covenants.  The  ability to draw on these
facilities  is also  conditioned  upon OE  making  certain  representations  and
warranties to the lending banks prior to drawing on its facilities,  including a
representation  that there has been no material  adverse change in its business,
its  condition  (financial  or  otherwise),  its results of  operations,  or its
prospects.

          OE's primary credit facilities do not contain provisions,  whereby its
ability to borrow would be  restricted  or denied,  or repayment of  outstanding
loans under the facilities accelerated,  as a result of any change in the credit
ratings of OE by any of the  nationally-recognized  rating agencies.  Borrowings
under the primary  facilities do contain  "pricing  grids",  whereby the cost of
funds  borrowed  under the  facilities  is related to the credit  ratings of the
company borrowing the funds.

          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,  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 in the first quarter of 2004 was 1.30%.

          In  March  2004,  Penn  completed  an  on-balance  sheet,   receivable
financing transaction which allows it to borrow up to $25 million. The borrowing
rate is based on bank commercial paper rates.  Penn is required to pay an annual
facility fee of 0.40% on the entire finance  limit.  The facility was undrawn as
of March 31, 2004. This facility matures on March 29, 2005.

                                       55

<PAGE>

           OE'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 of its securities is stable.

          On February 6, 2004, Moody's  downgraded  FirstEnergy senior unsecured
debt to Baa3 from Baa2 and downgraded  the senior secured debt of JCP&L,  Met-Ed
and Penelec to Baa1 from A2. Moody's also  downgraded the preferred stock rating
of JCP&L to Ba1 from Baa2 and the  senior  unsecured  rating of  Penelec to Baa2
from A2. The ratings of OE, CEI, TE and Penn were  confirmed.  Moody's said that
the  lower  ratings  were  prompted  by:  "1) high  consolidated  leverage  with
significant  holding company debt, 2) a degree of regulatory  uncertainty in the
service  territories in which the company  operates,  3) risks  associated  with
investigations of the causes of the August 2003 blackout, and related securities
litigation,  and 4) a  narrowing  of  the  ratings  range  for  the  FirstEnergy
operating utilities,  given the degree to which FirstEnergy increasingly manages
the utilities as a single system and the significant financial interrelationship
among the subsidiaries."

          On March 9, 2004, S&P stated that the NRC's permission for FirstEnergy
to restart the Davis-Besse nuclear plant was positive for credit quality because
it would positively affect cash flow by eliminating  replacement power costs and
"demonstrating   management's  ability  to  overcome  operational   challenges."
However, S&P did not change  FirstEnergy's  ratings or outlook because it stated
that financial performance still "significantly lags expectations and management
faces other operational hurdles."

       Cash Flows From Investing Activities

          Net use of cash for  investing  activities  totaled $11 million in the
first quarter of 2004, compared to net cash provided by investing  activities of
$106 million for the same period of 2003. The $117 million changes in funds from
investing  activities  resulted  primarily  from  loan  payments  to  associated
companies, offset in part by lower capital expenditures.

          During the last  three  quarters  of 2004,  capital  requirements  for
property  additions  and capital  leases are expected to be about $183  million,
including  $46 million for  nuclear  fuel.  OE has  additional  requirements  of
approximately  $68 million to meet sinking fund requirements for preferred stock
and  maturing   long-term  debt  during  the  remainder  of  2004.   These  cash
requirements  are expected to be satisfied  from  internal  cash and  short-term
credit arrangements.

          As of March 31,  2004,  OE has $278  million  in  deposits  pledged as
collateral to secure  reimbursement  obligations  related to certain  letters of
credit  supporting  OE's  obligations  to lessors under the Beaver Valley Unit 2
sale and leaseback arrangements.  The deposits had previously been classified as
a noncurrent asset in Other Property and Investments.  OE expects to replace the
cash collateralized LOC with a structure that would not require cash collateral.
OE  anticipates  using the cash from the deposit to repay short term debt in the
third quarter of 2004 and for other general corporate purposes.

Off-Balance Sheet Arrangements
------------------------------

          Obligations not included on OE's Consolidated  Balance Sheet primarily
consist of sale and  leaseback  arrangements  involving  Perry Unit 1 and Beaver
Valley  Unit 2. As of March  31,  2004,  the  present  value  of these  sale and
leaseback  operating lease  commitments,  net of trust  investments,  total $706
million.

Equity Price Risk
-----------------

          Included  in  OE's  nuclear   decommissioning  trust  investments  are
marketable equity securities carried at their market value of approximately $218
million  and  $209  million  as  of  March  31,  2004  and  December  31,  2003,
respectively.  A hypothetical  10% decrease in prices quoted by stock  exchanges
would result in a $22 million reduction in fair value as of March 31, 2004.

Outlook
-------

          Beginning  in 2001,  OE's  customers  were able to select  alternative
energy  suppliers.  OE  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.  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.

                                       56

<PAGE>


       Regulatory Matters

           Reliability Initiatives

          On  October  15,  2003,  NERC  issued a Near  Term  Action  Plan  that
contained  recommendations  for all control areas and  reliability  coordinators
with  respect  to  enhancing  system   reliability.   Approximately  20  of  the
recommendations  were directed at the FirstEnergy  companies and broadly focused
on  initiatives  that are  recommended  for  completion  by summer  2004.  These
initiatives  principally  relate to  changes in voltage  criteria  and  reactive
resources  management;  operational  preparedness  and action  plans;  emergency
response   capabilities;   and,  preparedness  and  operating  center  training.
FirstEnergy   presented  a  detailed   compliance  plan  to  NERC,   which  NERC
subsequently  endorsed on May 7, 2004, and the various  initiatives are expected
to be completed no later than June 30, 2004.

          On February 26-27, 2004, certain FirstEnergy companies participated in
a NERC Control Area Readiness Audit. This audit, part of an announced program by
NERC to review  control area  operations  throughout  much of the United  States
during 2004, is an  independent  review to identify areas for  improvement.  The
final  audit  report was  completed  on April 30,  2004.  The report  identified
positive  observations  and included  various  recommendations  for improvement.
FirstEnergy  is currently  reviewing the audit results and  recommendations  and
expects to  implement  those  relating to summer  2004 by June 30.  Based on its
review thus far, FirstEnergy believes that none of the recommendations  identify
a  need  for  any  incremental  material  investment  or  upgrades  to  existing
equipment.  FirstEnergy notes, however, that NERC 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.

          On March 1, 2004, certain  FirstEnergy  companies filed, in accordance
with a November 25, 2003 order from the PUCO, their plan for addressing  certain
issues  identified  by the PUCO from the U.S. - Canada Power System  Outage Task
Force  interim  report.  In  particular,   the  filing  addressed   upgrades  to
FirstEnergy's  control room computer  hardware and software and  enhancements to
the  training of control  room  operators.  The PUCO will review the plan before
determining the next steps, if any, in the proceeding.

          On April 22,  2004,  FirstEnergy  filed  with FERC the  results of the
FERC-ordered independent study of part of Ohio's power grid. The study examined,
among other things,  the reliability of the transmission grid in critical points
in  the  Northern  Ohio  area  and  the  need,   if  any,  for  reactive   power
reinforcements  during summer 2004 and 2005.  FirstEnergy is currently reviewing
the  results  of that  study and  expects  to  complete  the  implementation  of
recommendations  relating to 2004 by this summer.  Based on its review thus far,
FirstEnergy  believes that the study does not recommend any incremental material
investment or 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.

          With respect to each of the  foregoing  initiatives,  FirstEnergy  has
requested and NERC has agreed to provide, a technical assistance team of experts
to provide ongoing guidance and assistance in implementing and confirming timely
and successful completion.

           Ohio

          Beginning on January 1, 2001, OE's customers were able to choose their
electricity  suppliers.  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 regulated generation component (plus an incentive
for OE  customers),  and the  customer  receives a  generation  charge  from the
alternative  supplier.  OE has  continuing PLR  responsibility  to its franchise
customers through December 31, 2005.

          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  megawatts  (MW) of low cost  supply  to  unaffiliated  alternative
suppliers who serve customers within its service area. OE's  competitive  retail
sales affiliate, FES, acts as an alternate supplier for a portion of the load in
its franchise area.

          On October 21, 2003, the Ohio EUOC filed an application  with the PUCO
to establish  generation service rates beginning January 1, 2006, in response to
expressed concerns by the PUCO about price and supply uncertainty  following the
end of the market development period. The filing included two options:

          o   A  competitive  auction,  which would  establish a price for
              generation that customers would be charged during the period
              covered by the auction, or

                                       57

<PAGE>

          o   A  Rate  Stabilization  Plan,  which  would  extend  current
              generation prices through 2008, ensuring adequate generation
              supply at stable  prices,  and  continuing  OE's  support of
              energy efficiency and economic development efforts.

          Under  the first  option,  an  auction  would be  conducted  to secure
generation  service for OE's customers.  Beginning in 2006,  customers would pay
market prices for generation as determined by the auction.

          Under the Rate Stabilization  Plan option,  customers would have price
and supply  stability  through  2008 - three years  beyond the end of the market
development period - as well as the benefits of a competitive  market.  Customer
benefits would include:  customer  savings by extending the current five percent
discount on generation  costs and other customer  credits;  maintaining  current
distribution  base  rates  through  2007;  market-based  auctions  that  may  be
conducted  annually to ensure that  customers pay the lowest  available  prices;
extension of our support of  energy-efficiency  programs and the  potential  for
continuing the program to give  preferred  access to  nonaffiliated  entities to
generation  capacity if shopping drops below 20%. Under the proposed plan, OE is
requesting:

          o   Extension of the transition  cost  amortization  period from
              2006 to 2007;

          o   Deferral  of  interest  costs  on the  accumulated  shopping
              incentives  and  other  cost  deferrals  as  new  regulatory
              assets; and

          o   Ability to initiate a request to increase  generation  rates
              under certain limited conditions.

          On January 7, 2004,  the PUCO staff filed  testimony  on the  proposed
rate plan  generally  supporting the Rate  Stabilization  Plan as opposed to the
competitive  auction proposal.  Hearings began on February 11, 2004. On February
23, 2004,  after  consideration  of PUCO Staff comments and testimony as well as
those  provided by some of the  intervening  parties,  FirstEnergy  made certain
modifications  to the Rate  Stabilization  Plan. Oral arguments were held before
the PUCO on April 21 and a decision is  expected  from the PUCO in the Spring of
2004.

           Pennsylvania

          In late 2003,  the PPUC  issued a  Tentative  Order  implementing  new
reliability  benchmarks  and  standards.  In  connection  therewith,   the  PPUC
commenced a  rulemaking  procedure  to amend the  Electric  Service  Reliability
Regulations to implement these new benchmarks,  and create additional  reporting
on  reliability.  Although  neither  the  Tentative  Order  nor the  Reliability
Rulemaking has been finalized,  the PPUC ordered all  Pennsylvania  utilities to
begin filing quarterly  reports on November 1, 2003. The comment period for both
the  Tentative  Order and the  Proposed  Rulemaking  Order has  closed.  Penn is
currently  awaiting the PPUC to issue a final order in both  matters.  The order
will  determine  (1) the standards  and  benchmarks to be utilized,  and (2) the
details required in the quarterly and annual reports.

          On January 16,  2004,  the PPUC  initiated a formal  investigation  of
whether Penn's "service  reliability  performance  deteriorated to a point below
the  level of  service  reliability  that  existed  prior to  restructuring"  in
Pennsylvania.  Discovery has commenced in the proceeding and Penn's testimony is
due May 14,  2004.  Hearings  are  scheduled  to begin  August  3,  2004 in this
investigation  and the ALJ has been directed to issue a Recommended  Decision by
September  30,  2004,  in order to allow the PPUC time to issue a Final Order by
year end of 2004. Penn is unable to predict the outcome of the  investigation or
the impact of the PPUC order.

       Regulatory Assets-

          Regulatory  assets are costs which have been  authorized  by the PUCO,
PPUC and the FERC, for recovery from  customers in future  periods and,  without
such authorization,  would have been charged to income when incurred. All of the
OE Companies'  regulatory  assets are expected to continue to be recovered under
the provisions of their respective transition plan and rate restructuring plans.
The OE Companies' regulatory assets are as follows:


          Regulatory Assets as of
          ---------------------------------------------------------
                                          March 31,    December 31,
          Company                           2004          2003
          ---------------------------------------------------------
                                                (In millions)
          OE.........................     $1,348         $1,450
          Penn.......................         15             28
          ---------------------------------------------------------
             Consolidated Total......     $1,363         $1,478
===================================================================

                                       58

<PAGE>


       Environmental Matters

          Various federal,  state and local authorities  regulate OE with regard
to air and water  quality  and  other  environmental  matters.  The  effects  of
compliance  on OE with  regard to  environmental  matters  could have a material
adverse effect on its earnings and  competitive  position.  These  environmental
regulations affect OE'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,  OE believes it is in material  compliance with
existing  regulations  but is  unable to  predict  future  change in  regulatory
policies and what, if any, the effects of such change would be.

          OE is required to meet federally approved SO2 regulations.  Violations
of such  regulations  can result in shutdown  of the  generating  unit  involved
and/or civil or criminal  penalties of up to $31,500 for each day the unit is in
violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio
that allows for compliance based on a 30-day averaging period. OE cannot predict
what  action  the EPA  may  take  in the  future  with  respect  to the  interim
enforcement policy.

          In 1999 and 2000,  the EPA  issued  Notices  of  Violation  (NOV) or a
Compliance Order to nine utilities covering 44 power plants, including the W. H.
Sammis  Plant.  In addition,  the U.S.  Department  of Justice filed eight civil
complaints against various investor-owned utilities,  which included a complaint
against OE and Penn in the U.S.  District  Court for the  Southern  District  of
Ohio.  The NOV and  complaint  allege  violations  of the Clean Air Act based on
operation  and  maintenance  of the W. H. Sammis Plant dating back to 1984.  The
complaint  requests  permanent  injunctive relief to require the installation of
"best available control technology" and civil penalties of up to $27,500 per day
of  violation.  On August 7, 2003,  the  United  States  District  Court for the
Southern District of Ohio ruled that 11 projects  undertaken at the W. H. Sammis
Plant  between 1984 and 1998 required  pre-construction  permits under the Clean
Air Act. The ruling  concludes the liability phase of the case, which deals with
applicability of Prevention of Significant Deterioration provisions of the Clean
Air Act. The remedy  phase,  which is currently  scheduled to be ready for trial
beginning July 19, 2004, will address civil penalties and what, if any,  actions
should be taken to further  reduce  emissions at the plant.  In the ruling,  the
Court  indicated  that the remedies it "may consider and impose  involved a much
broader, equitable analysis, requiring the Court to consider air quality, public
health,  economic  impact,  and  employment  consequences.  The  Court  may also
consider  the less  than  consistent  efforts  of the EPA to apply  and  further
enforce the Clean Air Act." The potential penalties that may be imposed, as well
as the  capital  expenditures  necessary  to comply  with  substantive  remedial
measures that may be required,  could have a material  adverse  impact on the OE
Companies'  financial condition and results of operations.  Management is unable
to predict the ultimate outcome of this matter and no liability has been accrued
as of March 31, 2004.

          The OE Companies are complying with SO2 reduction  requirements  under
the Clean Air Act Amendments of 1990 by burning  lower-sulfur  fuel,  generating
more electricity from lower-emitting  plants,  and/or using emission allowances.
NOx  reductions  required  by the 1990  Amendments  are being  achieved  through
combustion  controls and the generation of more  electricity  at  lower-emitting
plants. In September 1998, the EPA finalized  regulations  requiring  additional
NOx reductions from the OE Companies'  facilities.  The EPA's NOx Transport Rule
imposes  uniform  reductions of NOx emissions (an  approximate  85% reduction in
utility plant NOx emissions from projected  2007  emissions)  across a region of
nineteen states (including Michigan,  New Jersey, Ohio and Pennsylvania) and the
District  of  Columbia  based  on a  conclusion  that  such  NOx  emissions  are
contributing  significantly to ozone levels in the eastern United States.  State
Implementation Plans (SIP) must comply by May 31, 2004 with individual state NOx
budgets.  Pennsylvania  submitted a SIP that  required  compliance  with the NOx
budgets  at the OE  Companies'  Pennsylvania  facilities  by May 1,  2003.  Ohio
submitted  a SIP  that  requires  compliance  with  the  NOx  budgets  at the OE
Companies'  Ohio  facilities by May 31, 2004. The OE Companies'  facilities have
complied with the NOx budgets in 2003 and 2004, respectively.

       Power Outage

          On August  14,  2003,  various  states  and parts of  southern  Canada
experienced a widespread power outage.  That outage affected  approximately  1.4
million  customers in  FirstEnergy's  service area.  On April 5, 2004,  the U.S.
-Canada Power System Outage Task Force released its final report on this outage.
The final report supercedes the interim report that had been issued in November,
2003. In the final report,  the Task Force concluded,  among other things,  that
the problems  leading to the outage began in  FirstEnergy's  Ohio service  area.
Specifically,   the  final  report  concludes,  among  other  things,  that  the
initiation of the August 14th power outage resulted from the coincidence on that
afternoon of several events,  including,  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 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 14th power outage and that it does not
adequately  address the  underlying  causes of the outage.  FirstEnergy  remains
convinced  that the outage  cannot be explained  by events on any one  utility's

                                       59

<PAGE>

system. The final report contains 46 "recommendations to prevent or minimize the
scope of future blackouts."  Forty-five of those recommendations relate to broad
industry  or policy  matters  while one  relates  to  activities  the Task Force
recommends be undertaken by FirstEnergy,  MISO,  PJM, and ECAR.  FirstEnergy has
undertaken  several  initiatives,  some prior to and some since the August  14th
power outage,  to enhance  reliability which are consistent with these and other
recommendations  and believes it will complete  those relating to summer 2004 by
June 30 (see Regulatory  Matters above).  As many of these  initiatives  already
were in process and  budgeted  in 2004,  FirstEnergy  does not believe  that any
incremental  expenses associated with additional  initiatives  undertaken during
2004 will  have a  material  effect  on its  operations  or  financial  results.
FirstEnergy  notes,   however,  that  the  applicable  government  agencies  and
reliability   coordinators   may  take  a  different   view  as  to  recommended
enhancements or may recommend  additional  enhancements in the future that could
require additional, material expenditures.

       Legal Matters

          Legal  proceedings  have been filed against  FirstEnergy in connection
with, among other things, the restatements in August 2003 by FirstEnergy and its
Ohio utility  subsidiaries of previously reported results, the August 14th power
outage described above, and the extended outage at the Davis-Besse Nuclear Power
Station.  Depending  upon the particular  proceeding,  the issues raised include
alleged  violations of federal  securities  laws,  breaches of fiduciary  duties
under state law by FirstEnergy  directors and officers,  and damages as a result
of one or more of the noted events.  The securities cases have been consolidated
into one action pending in federal court in Akron,  Ohio. The derivative actions
filed in federal court  likewise have been  consolidated  as a separate  matter,
also in federal  court in Akron.  There also are pending  derivative  actions in
state court.

          FirstEnergy's Ohio utility subsidiaries were also named as respondents
in two  regulatory  proceedings  initiated at the PUCO in response to complaints
alleging failure to provide  reasonable and adequate service stemming  primarily
from the August 14th power outage.  FirstEnergy  is vigorously  defending  these
actions,  but cannot predict the outcome of any of these  proceedings or whether
any further  regulatory  proceedings or legal actions may be instituted  against
them. In particular,  if FirstEnergy  were  ultimately  determined to have legal
liability in connection with these proceedings, it could have a material adverse
effect on its financial condition and results of operations.

          Various  lawsuits,  claims  and  proceedings  related  to OE's  normal
business  operations are pending  against OE, the most  significant of which are
described above.

Critical Accounting Policies
----------------------------

          OE prepares its consolidated  financial  statements in accordance with
GAAP.  Application of these principles often requires a high degree of judgment,
estimates  and  assumptions  that  affect  financial  results.  All  of  the  OE
Companies'  assets are subject to their own specific risks and uncertainties and
are regularly reviewed for impairment.  Assets related to the application of the
policies   discussed   below  are  similarly   reviewed  with  their  risks  and
uncertainties   reflecting  these  specific  factors.  The  OE  Companies'  more
significant accounting policies are described below.

       Regulatory Accounting

          The OE  Companies  are  subject  to  regulation  that sets the  prices
(rates) they are  permitted to charge  their  customers  based on costs that the
regulatory  agencies  determine the OE Companies  are  permitted to recover.  At
times,  regulators  permit the future recovery through rates of costs that would
be currently  charged to expense by an  unregulated  company.  This  rate-making
process  results in the  recording of  regulatory  assets  based on  anticipated
future cash inflows.  As a result of the changing  regulatory  framework in Ohio
and Pennsylvania, a significant amount of regulatory assets have been recorded -
$1.4 billion as of March 31, 2004.  OE regularly  reviews these assets to assess
their  ultimate   recoverability  within  the  approved  regulatory  guidelines.
Impairment  risk  associated  with these assets relates to  potentially  adverse
legislative, judicial or regulatory actions in the future.

       Revenue Recognition

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

                                       60

<PAGE>

       Pension and Other Postretirement Benefits Accounting

          FirstEnergy's  reported  costs of providing  non-contributory  defined
pension benefits and  postemployment  benefits other than pensions are dependent
upon  numerous  factors  resulting  from  actual  plan  experience  and  certain
assumptions.

          Pension  and  OPEB  costs  are   affected  by  employee   demographics
(including  age,  compensation  levels,  and employment  periods),  the level of
contributions  FirstEnergy makes to the plans, and earnings on plan assets. Such
factors may be further affected by business  combinations (such as FirstEnergy's
merger with GPU in November 2001),  which impacts  employee  demographics,  plan
experience  and other  factors.  Pension  and OPEB  costs are also  affected  by
changes  to key  assumptions,  including  anticipated  rates of  return  on plan
assets,  the discount rates and health care trend rates used in determining  the
projected benefit obligations for pension and OPEB costs.

          In accordance  with SFAS 87 and SFAS 106,  changes in pension and OPEB
obligations  associated with these factors may not be immediately  recognized as
costs on the income statement, but generally are recognized in future years over
the remaining average service period of plan participants.  SFAS 87 and SFAS 106
delay  recognition  of changes due to the  long-term  nature of pension and OPEB
obligations and the varying market  conditions likely to occur over long periods
of time. As such, significant portions of pension and OPEB costs recorded in any
period  may not  reflect  the actual  level of cash  benefits  provided  to plan
participants and are significantly influenced by assumptions about future market
conditions and plan participants' experience.

          In selecting an assumed discount rate, FirstEnergy considers currently
available rates of return on high-quality fixed income  investments  expected to
be   available   during  the  period  to  maturity  of  the  pension  and  other
postretirement  benefit  obligations.  Due to recent  declines in corporate bond
yields and interest rates in general,  FirstEnergy  reduced the assumed discount
rate as of December 31, 2003 to 6.25% from 6.75% used as of December 31, 2002.

          FirstEnergy's  assumed rate of return on pension plan assets considers
historical  market  returns and economic  forecasts for the types of investments
held by its pension trusts.  In 2003 and 2002, plan assets actually earned 24.0%
and (11.3)%,  respectively.  FirstEnergy's  pension  costs in 2003 and the first
quarter  of 2004 were  computed  assuming  a 9.0% rate of return on plan  assets
based upon  projections  of future  returns  and its  pension  trust  investment
allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash.

          Based on pension  assumptions  and pension  plan assets as of December
31, 2003,  FirstEnergy  will not be required to fund its pension  plans in 2004.
However,  health care cost trends have  significantly  increased and will affect
future  OPEB  costs.  The  2004  and  2003  composite  health  care  trend  rate
assumptions are approximately 10%-12% gradually decreasing to 5% in later years.
In determining  its trend rate  assumptions,  FirstEnergy  included the specific
provisions of its health care plans, the  demographics and utilization  rates of
plan participants,  actual cost increases  experienced in its health care plans,
and projections of future medical trend rates.

       Ohio Transition Cost Amortization

          In connection with FirstEnergy's  transition plan, the PUCO determined
allowable  transition costs based on amounts recorded on OE's regulatory  books.
These  costs  exceeded  those  deferred or  capitalized  on OE's  balance  sheet
prepared  under GAAP since they  included  certain costs which have not yet been
incurred.  OE uses an effective  interest  method for  amortizing its transition
costs, often referred to as a "mortgage-style"  amortization.  The interest rate
under this method is equal to the rate of return  authorized  by the PUCO in the
transition  plan for OE. In  computing  the  transition  cost  amortization,  OE
includes only the portion of the transition  revenues associated with transition
costs included on the balance sheet prepared under GAAP.  Revenues collected for
the off  balance  sheet  costs and the return  associated  with these  costs are
recognized as income when received.

       Long-Lived Assets

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

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

                                       61

<PAGE>

       Nuclear Decommissioning

          In accordance with SFAS 143, the OE Companies recognize an ARO for the
future  decommissioning  of  their  nuclear  power  plants.  The  ARO  liability
represents an estimate of the fair value of the OE Companies' current obligation
related to nuclear  decommissioning  and the retirement of other assets.  A fair
value measurement  inherently  involves  uncertainty in the amount and timing of
settlement  of the  liability.  The OE  Companies  used an  expected  cash  flow
approach (as  discussed in FASB  Concepts  Statement  No. 7) to measure the fair
value of the nuclear  decommissioning  ARO.  This approach  applies  probability
weighting  to  discounted  future cash flow  scenarios  that  reflect a range of
possible  outcomes.  The  scenarios  consider  settlement  of  the  ARO  at  the
expiration of the nuclear power plants' current license and settlement  based on
an extended license term.

New Accounting Standards and Interpretations
--------------------------------------------

       FSP  106-1,  "Accounting  and  Disclosure  Requirements  Related  to  the
       Medicare Prescription Drug, Improvement and Modernization Act of 2003"

          Issued   January  12,  2004,   FSP  106-1   permits  a  sponsor  of  a
postretirement  health care plan that  provides a  prescription  drug benefit to
make a one-time  election to defer  accounting  for the effects of the  Medicare
Act.  FirstEnergy  elected to defer the effects of the  Medicare  Act due to the
lack of specific guidance.  Pursuant to FSP 106-1,  FirstEnergy began accounting
for the effects of the Medicare Act  effective  January 1, 2004 as a result of a
February  2, 2004 plan  amendment  that  required  remeasurement  of the  plan's
obligations.  See Note 2 for a discussion  of the effect of the federal  subsidy
and plan amendment on the consolidated financial statements.

       FIN 46 (revised  December  2003),  "Consolidation  of  Variable  Interest
       Entities"

          In  December  2003,  the  FASB  issued  a  revised  interpretation  of
Accounting  Research  Bulletin  No.  51,  "Consolidated  Financial  Statements",
referred  to as  FIN  46R,  which  requires  the  consolidation  of a VIE  by an
enterprise if that enterprise is determined to be the primary beneficiary of the
VIE. As required,  OE adopted FIN 46R for interests in VIEs commonly referred to
as special-purpose  entities effective December 31, 2003 and for all other types
of  entities  effective  March  31,  2004.  Adoption  of FIN 46R did not  have a
material  impact on OE's  financial  statements  for the quarter ended March 31,
2004. See Note 2 for a discussion of Variable Interest Entities.

                                       62

<PAGE>

<TABLE>

                                    THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

                                         CONSOLIDATED STATEMENTS OF INCOME
                                                    (Unaudited)

<CAPTION>
                                                                                         Three Months Ended
                                                                                               March 31,
                                                                                      --------------------------
                                                                                         2004             2003
                                                                                      ---------         --------
                                                                                            (In thousands)

<S>                                                                                  <C>              <C>
OPERATING REVENUES..............................................................     $  426,535       $  419,771
                                                                                     ----------       ----------


OPERATING EXPENSES AND TAXES:
   Fuel.........................................................................         17,196           13,769
   Purchased power..............................................................        134,677          136,345
   Nuclear operating costs......................................................         32,715           55,361
   Other operating costs........................................................         64,027           61,899
                                                                                     ----------       ----------
       Total operation and maintenance expenses.................................        248,615          267,374
   Provision for depreciation and amortization..................................         61,776           51,357
   General taxes................................................................         38,818           39,713
   Income taxes.................................................................          4,013            7,316
                                                                                     ----------       ----------
       Total operating expenses and taxes.......................................        353,222          365,760
                                                                                     ----------       ----------


OPERATING INCOME................................................................         73,313           54,011


OTHER INCOME....................................................................         11,727            4,741
                                                                                     ----------       ----------

INCOME BEFORE NET INTEREST CHARGES..............................................         85,040           58,752
                                                                                     ----------       ----------


NET INTEREST CHARGES:
   Interest on long-term debt...................................................         32,211           40,640
   Allowance for borrowed funds used during construction........................         (1,711)          (2,167)
   Other interest expense.......................................................          6,065               31
   Subsidiary's preferred dividend requirements.................................             --            4,950
                                                                                     ----------       ----------
       Net interest charges.....................................................         36,565           43,454
                                                                                     ----------       ----------


INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE............................         48,475           15,298

Cumulative effect of accounting change (Net of income taxes
  of $30,168,000) (Note 2)......................................................             --           42,378
                                                                                     ----------       ----------


NET INCOME......................................................................         48,475           57,676


PREFERRED STOCK DIVIDEND REQUIREMENTS...........................................          1,744             (759)
                                                                                     ----------      -----------


EARNINGS ON COMMON STOCK........................................................     $   46,731       $   58,435
                                                                                     ==========       ==========


<FN>
The preceding  Notes to Consolidated  Financial  Statements as they relate to The Cleveland  Electric  Illuminating
Company are an integral part of these statements.
</FN>

                                                        63

</TABLE>

<PAGE>

<TABLE>

                                  THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

                                          CONSOLIDATED BALANCE SHEETS
                                                  (Unaudited)

<CAPTION>
                                                                                        March 31,       December 31,
                                                                                          2004             2003
                                                                                       ----------------------------
                                                                                              (In thousands)
                                         ASSETS
UTILITY PLANT:
<S>                                                                                    <C>              <C>
   In service.....................................................................     $4,334,014       $4,232,335
   Less-Accumulated provision for depreciation....................................      1,880,144        1,857,588
                                                                                       -----------      ----------
                                                                                        2,453,870        2,374,747
                                                                                       ----------       ----------
   Construction work in progress-
     Electric plant...............................................................         95,271          159,897
     Nuclear fuel.................................................................             --           21,338
                                                                                       ----------       ----------
                                                                                           95,271          181,235
                                                                                       ----------       ----------
                                                                                        2,549,141        2,555,982
                                                                                       ----------       ----------
OTHER PROPERTY AND INVESTMENTS:
   Investment in lessor notes.....................................................        584,950          605,915
   Nuclear plant decommissioning trusts...........................................        332,303          313,621
   Long-term notes receivable from associated companies...........................         97,212          107,946
   Other..........................................................................         17,818           23,636
                                                                                       ----------       ----------
                                                                                        1,032,283        1,051,118
                                                                                       ----------       ----------
CURRENT ASSETS:
   Cash and cash equivalents......................................................            200           24,782
   Receivables-
     Customers....................................................................          8,784           10,313
     Associated companies.........................................................         43,741           40,541
     Other (less accumulated provisions of $1,454,000 and $1,765,000, respectively,
       for uncollectible accounts)................................................         39,742          185,179
   Notes receivable from associated companies.....................................         14,138              482
   Materials and supplies, at average cost........................................         52,971           50,616
   Prepayments and other..........................................................          2,616            4,511
                                                                                       ----------       ----------
                                                                                          162,192          316,424
                                                                                       ----------       ----------
DEFERRED CHARGES:
   Regulatory assets..............................................................      1,021,972        1,056,050
   Goodwill.......................................................................      1,693,629        1,693,629
   Property taxes.................................................................         77,122           77,122
   Other..........................................................................         23,599           23,123
                                                                                       ----------       ----------
                                                                                        2,816,322        2,849,924
                                                                                       ----------       ----------
                                                                                       $6,559,938       $6,773,448
                                                                                       ==========       ==========
                           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       $1,281,962
     Accumulated other comprehensive income.......................................          7,405            2,653
     Retained earnings............................................................        485,944          494,212
                                                                                       ----------       ----------
         Total common stockholder's equity........................................      1,775,311        1,778,827
   Preferred stock not subject to mandatory redemption............................         96,404           96,404
   Long-term debt and other long-term obligations.................................      1,954,569        1,884,643
                                                                                       ----------       ----------
                                                                                        3,826,284        3,759,874
                                                                                       ----------       ----------
CURRENT LIABILITIES:
   Currently payable long-term debt and preferred stock...........................        379,924          387,414
   Accounts payable-
     Associated companies.........................................................        268,045          245,815
     Other........................................................................          7,499            7,342
   Notes payable to associated companies..........................................         16,203          188,156
   Accrued  taxes.................................................................        134,596          202,522
   Accrued interest...............................................................         46,111           37,872
   Lease market valuation liability...............................................         60,200           60,200
   Other..........................................................................         33,337           76,722
                                                                                       ----------       ----------
                                                                                          945,915        1,206,043
                                                                                       ----------       ----------
NONCURRENT LIABILITIES:
   Accumulated deferred income taxes..............................................        485,976          486,048
   Accumulated deferred investment tax credits....................................         64,750           65,996
   Asset retirement obligation....................................................        259,049          254,834
   Retirement benefits............................................................        110,833          105,101
   Lease market valuation liability...............................................        713,400          728,400
   Other..........................................................................        153,731          167,152
                                                                                       ----------       ----------
                                                                                        1,787,739        1,807,531
                                                                                       ----------       ----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 3)................................
                                                                                       ----------       ----------
                                                                                       $6,559,938       $6,773,448
                                                                                       ==========       ==========

<FN>
The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating
Company are an integral part of these balance sheets.
</FN>

                                                     64

</TABLE>

<PAGE>

<TABLE>

                                  THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

                                     CONSOLIDATED STATEMENTS OF CASH FLOWS
                                                  (Unaudited)

<CAPTION>
                                                                                        Three Months Ended
                                                                                             March 31,
                                                                                   ----------------------------
                                                                                      2004              2003
                                                                                   ---------          ---------
                                                                                         (In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
<S>                                                                                <C>                <C>
Net income......................................................................   $  48,475          $  57,676
   Adjustments to reconcile net income to net
     cash from operating activities-
       Provision for depreciation and amortization..............................      61,776             51,357
       Nuclear fuel and capital lease amortization..............................       5,107              5,044
       Other amortization.......................................................      (4,723)            (4,613)
       Deferred operating lease costs, net......................................     (41,635)           (41,603)
       Deferred income taxes, net...............................................      (2,793)            33,804
       Amortization of investment tax credits...................................      (1,246)            (1,202)
       Accrued retirement benefit obligations...................................       5,732              1,797
       Accrued compensation, net................................................       1,453              2,580
       Cumulative effect of accounting change (Note 2)..........................          --            (72,547)
       Receivables..............................................................     143,766             15,242
       Materials and supplies...................................................      (2,355)              (128)
       Accounts payable.........................................................      22,387            (44,129)
       Accrued taxes............................................................     (67,926)             2,896
       Accrued interest.........................................................       8,239              8,844
       Prepayments and other current assets.....................................       1,895              1,772
       Other....................................................................     (18,362)           (11,970)
                                                                                   ---------          ---------
         Net cash provided from operating activities............................     159,790              4,820
                                                                                   ---------          ---------

CASH FLOWS FROM FINANCING ACTIVITIES:
   New Financing-
     Long-term debt.............................................................      80,967                 --
     Short-term borrowings, net.................................................          --             33,245
   Redemptions and Repayments-
     Long-term debt.............................................................      (7,985)           (45,103)
     Short-term borrowings, net.................................................    (182,167)                --
   Dividend Payments-
     Common stock...............................................................     (55,000)                --
     Preferred stock............................................................      (1,744)            (1,865)
                                                                                   ---------          ---------
         Net cash used for financing activities.................................    (165,929)           (13,723)
                                                                                   ---------          ---------

CASH FLOWS FROM INVESTING ACTIVITIES:
   Property additions...........................................................     (17,868)           (31,218)
   Loans to associated companies, net...........................................      (2,922)                --
   Investments in lessor notes..................................................      20,965             19,071
   Contributions to nuclear decommissioning trusts..............................      (7,256)            (7,256)
   Other........................................................................     (11,362)            (1,250)
                                                                                   ---------          ---------
         Net cash used for investing activities.................................     (18,443)           (20,653)
                                                                                   ---------          ---------

Net decrease in cash and cash equivalents.......................................     (24,582)           (29,556)
Cash and cash equivalents at beginning of period ...............................      24,782             30,382
                                                                                   ---------          ---------
Cash and cash equivalents at end of period......................................   $     200          $     826
                                                                                   =========          =========


<FN>
The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating
Company are an integral part of these statements.
</FN>

                                                      65

</TABLE>

<PAGE>



<PAGE>


                        REPORT OF INDEPENDENT ACCOUNTANTS


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, 2004, and the
related  consolidated  statements  of  income  and  cash  flows  for each of the
three-month  periods  ended March 31,  2004 and 2003.  These  interim  financial
statements are the responsibility of the Company's management.

We conducted our review in accordance with standards established by the American
Institute  of  Certified  Public  Accountants.  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 generally
accepted  auditing  standards,  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 auditing  standards  generally accepted
in the  United  States  of  America,  the  consolidated  balance  sheet  and the
consolidated  statement  of  capitalization  as of December  31,  2003,  and the
related  consolidated   statements  of  income,   common  stockholder's  equity,
preferred  stock,  cash flows and taxes for the year then  ended (not  presented
herein),  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 1(F) 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 February 25, 2004, we expressed
an  unqualified  opinion  on those  consolidated  financial  statements.  In our
opinion,  the information set forth in the accompanying  condensed  consolidated
balance sheet as of December 31, 2003, 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 7, 2004

                                       66

<PAGE>


                   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 them 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 2004 decreased to $47
million from $58 million in the first quarter of 2003.  Earnings on common stock
in the first  quarter of 2003  included an after-tax  credit of $42 million from
the cumulative  effect of an accounting  change due to the adoption of SFAS 143.
Income  before  the  cumulative  effect  increased  to $48  million in the first
quarter of 2004 from $15 million in the first quarter of 2003.

          Operating  revenues  increased  by $7  million  or 1.6%  in the  first
quarter of 2004 from the same period in 2003.  Higher  revenues  resulted from a
$14 million (18.3%)  increase in wholesale sales partially  offset by a decrease
in  kilowatt-hour  sales to retail  customers.  The increase in wholesale  sales
revenues  (primarily  to FES) was due to  increased  fossil  generation  (at the
Mansfield  Plant)  available  for  sale to  FES.  Electric  generation  services
provided by  alternative  suppliers  as a percent of total sales  deliveries  in
CEI's  franchise area increased to 42.5% in the first quarter of 2004 from 38.0%
in the first quarter of 2003,  resulting in a 4.8% decrease in generation retail
sales and reducing generation sales revenue by $4 million.

          Distribution  deliveries  increased  2.6% in the first quarter of 2004
compared to the  corresponding  quarter of 2003,  with increases in all customer
sectors  (residential,  commercial and  industrial).  The $5 million decrease in
revenues from electricity  throughput in the first quarter of 2004 from the same
quarter  of the prior year was due to lower  composite  prices,  offsetting  the
effect of the higher distribution deliveries.

          Under the Ohio transition  plan, CEI provides  incentives to customers
to encourage switching to alternative energy providers. These revenue reductions
are deferred for future recovery under the transition plan and do not materially
affect current period earnings.  The change in shopping  customer sales by class
(resulting in lower composite prices in 2004 compared to 2003) offset the effect
of increased shopping levels and resulted in a $3 million revenue increase.

          Changes in electric  generation sales and  distribution  deliveries in
the first quarter of 2004 from the first  quarter of 2003 are  summarized in the
following table:


                  Changes in Kilowatt-Hour Sales
                  ---------------------------------------------------
                  Increase (Decrease)
                  Electric Generation:
                    Retail..................................    (4.8)%
                    Wholesale...............................    10.0%
                  ---------------------------------------------------
                  Total Electric Generation Sales...........     2.3%
                  ===================================================
                  Distribution Deliveries:
                    Residential.............................     1.3%
                    Commercial..............................     0.9%
                    Industrial..............................     4.5%
                  ---------------------------------------------------
                  Total Distribution Deliveries.............     2.6%
                  ===================================================


       Operating Expenses and Taxes

          Total  operating  expenses  and taxes  decreased by $13 million in the
first  quarter  of 2004 from the first  quarter  of 2003.  The  following  table
presents changes from the prior year by expense category.

                                       67

<PAGE>



              Operating Expenses and Taxes - Changes
              ----------------------------------------------------------------
               Increase (Decrease)                                (In millions)
              Fuel.............................................       $  3
              Purchased power .................................         (1)
              Nuclear operating costs..........................        (23)
              Other operating costs............................          2
              ------------------------------------------------------------
                Total operation and maintenance expenses.......        (19)

              Provision for depreciation and amortization......         10
              General taxes....................................         (1)
              Income taxes.....................................         (3)
              -------------------------------------------------------------
                Total operating expenses and taxes.............       $(13)
              =============================================================

          Higher  fuel  costs in the first  quarter of 2004,  compared  with the
first quarter of 2003,  primarily  resulted from increased fossil generation (up
64%).  Lower  purchased  power costs reflect  reduced  kilowatt-hours  purchased
offset in part by higher unit costs.  Reductions in nuclear  operating  costs in
the  first  quarter  of 2004,  compared  with the  first  quarter  of 2003  were
primarily  due to  the  reduction  in  incremental  costs  associated  with  the
Davis-Besse  outage  (see  Davis-Besse  Restoration).   The  increase  in  other
operating costs resulted in part from higher employee benefit costs.

          The increase in  depreciation  and  amortization  charges in the first
quarter of 2004,  compared with the first quarter of 2003,  was primarily due to
increased  amortization  of  regulatory  assets ($6 million) and lower  shopping
incentive deferrals ($3 million).

          Income taxes in the first  quarter of 2004  included  credits from the
favorable  resolution  of certain  tax matters  that had been  reserved in prior
periods, thus reducing CEI's reported effective income tax rate.

         Other Income

          The increase in other income was principally due to  approximately  $7
million of interest income from Shippingport  which was consolidated into CEI as
of December 31, 2003.

         Net Interest Charges

          Net  interest  charges  continued  to trend  lower,  decreasing  by $7
million in the first quarter of 2004 from the same quarter last year, reflecting
redemptions and  refinancings  since the end of the first quarter of 2003. CEI's
long-term  debt  redemptions  of $8 million during the first quarter of 2004 are
expected to result in annualized savings of approximately $700,000.

         Cumulative Effect of Accounting Change

          Upon adoption of SFAS 143 in the first  quarter of 2003,  CEI recorded
an  after-tax  credit  to net  income  of $42  million.  The  cumulative  effect
adjustment for unrecognized  depreciation,  accretion offset by the reduction in
the existing decommissioning  liabilities and ceasing the accounting practice of
depreciating  non-regulated  generation assets using a cost of removal component
resulted  in a $73  million  increase  to income,  or $42  million net of income
taxes.

           Preferred Stock Dividend Requirements

          Preferred  stock  dividend  requirements  increased  $3 million in the
first  quarter  of  2004,  compared  to the same  period  last  year,  due to an
adjustment that reduced costs in the first quarter of 2003.

Capital Resources and Liquidity
-------------------------------

          CEI's cash requirements in 2004 for operating  expenses,  construction
expenditures,  scheduled debt  maturities and preferred  stock  redemptions  are
expected  to be  met  without  increasing  its  net  debt  and  preferred  stock
outstanding.  Available  borrowing  capacity under short-term  credit facilities
will be used to manage working capital requirements.  Over the next three years,
CEI  expects  to meet its  contractual  obligations  with cash from  operations.
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, 2004,  CEI had $200,000 of cash and cash  equivalents,
compared  with $25 million as of December  31, 2003 which  included a portion of
the NRG settlement  claim sold in January 2004. The major sources for changes in
these balances are summarized below.

                                       68

<PAGE>

       Cash Flows From Operating Activities

          Cash provided from  operating  activities  during the first quarter of
2004, compared with the first quarter of 2003 were as follows:


              Operating Cash Flows                     2004          2003
              -------------------------------------------------------------
                                                          (In millions)

              Cash earnings (1)....................     $ 72         $ 32
              Working capital and other............       88          (27)
              -------------------------------------------------------------

              Total................................     $160         $  5
              =============================================================

              (1) Includes net income, depreciation and
                  amortization, deferred operating lease costs,
                  deferred income taxes, investment tax credits
                  and major noncash charges.


          Net cash provided from operating  activities increased $155 million in
the first  quarter of 2004 from the first  quarter of 2003 as a result of a $115
million  increase  from  working  capital  and other  changes  and a $40 million
increase in cash  earnings.  The largest  factor  contributing  to the change in
working  capital was receiving  the proceeds from the  settlement of CEI's claim
against NRG, Inc. for the terminated sale of four power plants.

       Cash Flows From Financing Activities

          Net cash used for financing  activities  increased $152 million in the
first quarter of 2004 from the first quarter of 2003. The increase in funds used
for  financing  activities  was the result of a $215  million  net  increase  in
short-term  borrowing  repayments  and a $55 million  increase  in common  stock
dividends,  partially  offset  by new  financings  of $81  million  and  reduced
security redemptions.

          CEI had about $14  million of cash and  temporary  investments  (which
include short-term notes receivable from associated companies) and approximately
$16  million  of  short-term  indebtedness  as of March  31,  2004.  CEI had the
capability to issue $1.1 billion of additional first mortgage bonds on the basis
of property additions and retired bonds. CEI has no restrictions on the issuance
of preferred stock.

          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 2004 was 1.30%.

           CEI'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 of its securities is stable.

          On February 6, 2004, Moody's  downgraded  FirstEnergy senior unsecured
debt to Baa3 from Baa2 and downgraded  the senior secured debt of JCP&L,  Met-Ed
and Penelec to Baa1 from A2. Moody's also  downgraded the preferred stock rating
of JCP&L to Ba1 from Baa2 and the  senior  unsecured  rating of  Penelec to Baa2
from A2. The ratings of OE, CEI, TE and Penn were  confirmed.  Moody's said that
the  lower  ratings  were  prompted  by:  "1) high  consolidated  leverage  with
significant  holding company debt, 2) a degree of regulatory  uncertainty in the
service  territories in which the company  operates,  3) risks  associated  with
investigations of the causes of the August 2003 blackout, and related securities
litigation,  and 4) a  narrowing  of  the  ratings  range  for  the  FirstEnergy
operating utilities,  given the degree to which FirstEnergy increasingly manages
the utilities as a single system and the significant financial interrelationship
among the subsidiaries."

          On March 9, 2004, S&P stated that the NRC's permission for FirstEnergy
to restart the Davis-Besse nuclear plant was positive for credit quality because
it would positively affect cash flow by eliminating  replacement power costs and
"demonstrating   management's  ability  to  overcome  operational   challenges."
However, S&P did not change  FirstEnergy's  ratings or outlook because it stated
that financial performance still "significantly lags expectations and management
faces other operational hurdles."

       Cash Flows From Investing Activities

          Net cash used for  investing  activities  decreased  $2 million in the
first  quarter of 2004 from the first  quarter of 2003 and was  primarily due to
lower capital expenditures.

                                       69

<PAGE>

          During the last  three  quarters  of 2004,  capital  requirements  for
property additions are expected to be about $106 million,  including $27 million
for nuclear fuel. CEI has additional  requirements of approximately $281 million
to meet sinking fund  requirements  for preferred  stock and maturing  long-term
debt during the remainder of 2004.

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, 2004,  the present value of these sale and  leaseback  operating
lease commitments, net of trust investments, total $109 million.

          CEI 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 $132 million of
off-balance sheet financing as of March 31, 2004.

          As of March 31, 2004,  off-balance sheet arrangements  include certain
statutory business trusts created by CEI to issue trust preferred  securities in
the amount of $100  million.  These  trusts were  included  in the  consolidated
financial  statements of FirstEnergy  prior to the adoption of FIN 46R effective
December 31, 2003, but have subsequently been deconsolidated  under FIN 46R (see
Note 2 - Variable Interest Entities).  The deconsolidation under FIN 46R did not
result in any change in outstanding debt.

Equity Price Risk
-----------------

          Included  in  CEI's  nuclear  decommissioning  trust  investments  are
marketable equity securities carried at their market value of approximately $202
million  and  $188  million  as  of  March  31,  2004  and  December  31,  2003,
respectively.  A hypothetical  10% decrease in prices quoted by stock  exchanges
would result in a $20 million reduction in fair value as of March 31, 2004.

Outlook
-------

          Beginning in 2001,  CEI's  customers  were able to select  alternative
energy  suppliers.  CEI  continues  to deliver  power to  residential  homes and
businesses through its existing  distribution  system,  which remains regulated.
Customer rates were  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  regulated   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.

          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,  2004 and  December  2003 were  $1.02  billion  and $1.06
billion,  respectively.  All of CEI's regulatory assets are expected to continue
to be recovered under the provisions of the transition plan.

          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. CEI's competitive  retail
sales affiliate, FES, acts as an alternate supplier for a portion of the load in
its franchise area.

          On October 21, 2003, the Ohio EUOC filed an application  with the PUCO
to establish  generation service rates beginning January 1, 2006, in response to
expressed concerns by the PUCO about price and supply uncertainty  following the
end of the market development period. The filing included two options:

          o   A  competitive  auction,  which would  establish a price for
              generation that customers would be charged during the period
              covered by the auction, or

                                       70

<PAGE>

          o   A  Rate  Stabilization  Plan,  which  would  extend  current
              generation prices through 2008, ensuring adequate generation
              supply at stable  prices,  and  continuing  CEI's support of
              energy efficiency and economic development efforts.

          Under  the first  option,  an  auction  would be  conducted  to secure
generation service for CEI's customers.  Beginning in 2006,  customers would pay
market prices for generation as determined by the auction.

          Under the Rate Stabilization  Plan option,  customers would have price
and supply  stability  through  2008 - three years  beyond the end of the market
development period - as well as the benefits of a competitive  market.  Customer
benefits would include:  customer  savings by extending the current five percent
discount on generation  costs and other customer  credits;  maintaining  current
distribution  base  rates  through  2007;  market-based  auctions  that  may  be
conducted  annually to ensure that  customers pay the lowest  available  prices;
extension of CEI's support of  energy-efficiency  programs and the potential for
continuing the program to give  preferred  access to  nonaffiliated  entities to
generation capacity if shopping drops below 20%. Under the proposed plan, CEI is
requesting:

          o   Extension of the transition  cost  amortization  period from
              2008 to mid-2009;

          o   Deferral  of  interest  costs  on the  accumulated  shopping
              incentives  and  other  cost  deferrals  as  new  regulatory
              assets; and

          o   Ability to initiate a request to increase  generation  rates
              under certain limited conditions.

          On January 7, 2004,  the PUCO staff filed  testimony  on the  proposed
rate plan  generally  supporting the Rate  Stabilization  Plan as opposed to the
competitive  auction proposal.  Hearings began on February 11, 2004. On February
23, 2004,  after  consideration  of PUCO Staff comments and testimony as well as
those  provided by some of the  intervening  parties,  FirstEnergy  made certain
modifications  to the Rate  Stabilization  Plan. Oral arguments were held before
the PUCO on April 21 and a decision is  expected  from the PUCO in the Spring of
2004.

       Reliability Initiatives

          On  October  15,  2003,  NERC  issued a Near  Term  Action  Plan  that
contained  recommendations  for all control areas and  reliability  coordinators
with  respect  to  enhancing  system   reliability.   Approximately  20  of  the
recommendations  were directed at the FirstEnergy  companies and broadly focused
on  initiatives  that are  recommended  for  completion  by summer  2004.  These
initiatives  principally  relate to  changes in voltage  criteria  and  reactive
resources  management;  operational  preparedness  and action  plans;  emergency
response   capabilities;   and,  preparedness  and  operating  center  training.
FirstEnergy   presented  a  detailed   compliance  plan  to  NERC,   which  NERC
subsequently  endorsed on May 7, 2004, and the various  initiatives are expected
to be completed no later than June 30, 2004.

          On February 26-27, 2004, certain FirstEnergy companies participated in
a NERC Control Area Readiness Audit. This audit, part of an announced program by
NERC to review  control area  operations  throughout  much of the United  States
during 2004, is an  independent  review to identify areas for  improvement.  The
final  audit  report was  completed  on April 30,  2004.  The report  identified
positive  observations  and included  various  recommendations  for improvement.
FirstEnergy  is currently  reviewing the audit results and  recommendations  and
expects to  implement  those  relating to summer  2004 by June 30.  Based on its
review thus far, FirstEnergy believes that none of the recommendations  identify
a  need  for  any  incremental  material  investment  or  upgrades  to  existing
equipment.  FirstEnergy notes, however, that NERC 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.

          On March 1, 2004, certain  FirstEnergy  companies filed, in accordance
with a November 25, 2003 order from the PUCO, their plan for addressing  certain
issues  identified  by the PUCO from the U.S. - Canada Power System  Outage Task
Force  interim  report.  In  particular,   the  filing  addressed   upgrades  to
FirstEnergy's  control room computer  hardware and software and  enhancements to
the  training of control  room  operators.  The PUCO will review the plan before
determining the next steps, if any, in the proceeding.

          On April 22,  2004,  FirstEnergy  filed  with FERC the  results of the
FERC-ordered independent study of part of Ohio's power grid. The study examined,
among other things,  the reliability of the transmission grid in critical points
in  the  Northern  Ohio  area  and  the  need,   if  any,  for  reactive   power
reinforcements  during summer 2004 and 2005.  FirstEnergy is currently reviewing
the  results  of that  study and  expects  to  complete  the  implementation  of
recommendations  relating to 2004 by this summer.  Based on its review thus far,
FirstEnergy  believes that the study does not recommend any incremental material
investment or 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.

                                       71

<PAGE>

          With respect to each of the  foregoing  initiatives,  FirstEnergy  has
requested and NERC has agreed to provide, a technical assistance team of experts
to provide ongoing guidance and assistance in implementing and confirming timely
and successful completion.

       Davis-Besse Restoration

          On April 30, 2002,  the NRC initiated a formal  inspection  process at
the  Davis-Besse  nuclear plant.  This action was taken in response to corrosion
found by FENOC in the  reactor  vessel  head near the  nozzle  penetration  hole
during a  refueling  outage in the first  quarter  of 2002.  The  purpose of the
formal  inspection  process was to establish  criteria for NRC  oversight of the
licensee's  performance  and to  provide a record of the  major  regulatory  and
licensee actions taken,  and technical issues resolved.  This process led to the
NRC's March 8, 2004 approval of Davis-Besse's restart.

          Restart  activities  included both hardware and management  issues. In
addition  to  refurbishment  and  installation  work at the  plant,  FENOC  made
significant  management  and  human  performance  changes  with  the  intent  of
enhancing the proper  safety  culture  throughout  the  workforce.  The focus of
activities  in  the  first  quarter  of  2004  involved   management  and  human
performance issues. As a result,  incremental  maintenance costs declined in the
first quarter of 2004 compared to the same period in 2003 as emphasis shifted to
performance  issues;  however,  replacement power costs were higher in the first
quarter  of 2004.  The  plant's  generating  equipment  was  tested  in March in
preparation for resumption of operation.  On April 4, 2004,  Davis-Besse resumed
generating electricity at 100% power.

          Incremental  costs  associated  with the extended  Davis-Besse  outage
(CEI's share - 51.38%) for the first quarter of 2004 and 2003 were as follows:

                                        Three Months Ended
                                             March 31,
                                        ------------------             Increase
Costs of Davis-Besse Extended Outage    2004           2003           (Decrease)
--------------------------------------------------------------------------------
                                                     (In millions)
Incremental Expense
  Replacement power.................     $64               $52             $ 12
  Maintenance.......................       1                36              (35)
--------------------------------------------------------------------------------
      Total.........................     $65               $88             $(23)
================================================================================

Incremental Net of Tax Expense......     $38               $52             $(14)
================================================================================


       Environmental Matters

          Various federal,  state and local authorities regulate CEI with regard
to air and water  quality  and  other  environmental  matters.  The  effects  of
compliance  on CEI with regard to  environmental  matters  could have a material
adverse effect on its earnings and  competitive  position.  These  environmental
regulations affect CEI'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,  CEI believes it is in material compliance with
existing  regulations  but is  unable to  predict  future  change in  regulatory
policies and what, if any, the effects of such change would be.

          CEI is required to meet federally approved SO2 regulations. Violations
of such  regulations  can result in shutdown  of the  generating  unit  involved
and/or civil or criminal  penalties of up to $31,500 for each day the unit is in
violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio
that  allows  for  compliance  based on a 30-day  averaging  period.  CEI cannot
predict  what action the EPA may take in the future with  respect to the interim
enforcement policy.

          CEI is complying with SO2 reduction  requirements  under the Clean Air
Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity
from lower-emitting  plants,  and/or using emission  allowances.  NOx reductions
required by the 1990 Amendments are being achieved through  combustion  controls
and the generation of more electricity at  lower-emitting  plants.  In September
1998, the EPA finalized  regulations  requiring  additional NOx reductions  from
CEI's Ohio and  Pennsylvania  facilities.  The EPA's NOx Transport  Rule imposes
uniform  reductions of NOx emissions  (an  approximate  85% reduction in utility
plant NOx emissions from projected 2007  emissions)  across a region of nineteen
states (including Michigan,  New Jersey, Ohio and Pennsylvania) and the District
of Columbia  based on a  conclusion  that such NOx  emissions  are  contributing
significantly to ozone levels in the eastern United States. State Implementation
Plans  (SIP) must  comply by May 31,  2004 with  individual  state NOx  budgets.
Pennsylvania  submitted a SIP that required  compliance  with the NOx budgets at
CEI's Pennsylvania facilities by May 1, 2003. Ohio submitted a SIP that requires
compliance with the NOx budgets at CEI's Ohio facilities by May 31, 2004.  CEI's
facilities have complied with the NOx budgets in 2003 and 2004, respectively.

                                       72

<PAGE>

          CEI 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 be held  liable  on a joint and  several  basis.  Therefore,  environmental
liabilities   that  are  considered   probable  have  been   recognized  on  the
Consolidated  Balance Sheets,  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. CEI has accrued  liabilities  aggregating
approximately  $2.4  million as of March 31,  2004.  CEI  accrues  environmental
liabilities only when it can conclude that it is probable that an obligation for
such  costs  exists  and can  reasonably  determine  the  amount of such  costs.
Unasserted  claims  are  reflected  in  CEI's   determination  of  environmental
liabilities  and are  accrued  in the  period  that they are both  probable  and
reasonably estimable.

       Power Outage

          On August  14,  2003,  various  states  and parts of  southern  Canada
experienced a widespread power outage.  That outage affected  approximately  1.4
million  customers in  FirstEnergy's  service area.  On April 5, 2004,  the U.S.
-Canada Power System Outage Task Force released its final report on this outage.
The final report supercedes the interim report that had been issued in November,
2003. In the final report,  the Task Force concluded,  among other things,  that
the problems  leading to the outage began in  FirstEnergy's  Ohio service  area.
Specifically,   the  final  report  concludes,  among  other  things,  that  the
initiation of the August 14th power outage resulted from the coincidence on that
afternoon of several events,  including,  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 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 14th power outage and that it does not
adequately  address the  underlying  causes of the outage.  FirstEnergy  remains
convinced  that the outage  cannot be explained  by events on any one  utility's
system. The final report contains 46 "recommendations to prevent or minimize the
scope of future blackouts."  Forty-five of those recommendations relate to broad
industry  or policy  matters  while one  relates  to  activities  the Task Force
recommends be undertaken by FirstEnergy,  MISO,  PJM, and ECAR.  FirstEnergy has
undertaken  several  initiatives,  some prior to and some since the August  14th
power outage,  to enhance  reliability which are consistent with these and other
recommendations  and believes it will complete  those relating to summer 2004 by
June 30 (see  Reliability  Initiatives  above).  As  many of  these  initiatives
already were in process and budgeted in 2004,  FirstEnergy does not believe that
any  incremental  expenses  associated with  additional  initiatives  undertaken
during 2004 will have a material effect on its operations or financial  results.
FirstEnergy  notes,   however,  that  the  applicable  government  agencies  and
reliability   coordinators   may  take  a  different   view  as  to  recommended
enhancements or may recommend  additional  enhancements in the future that could
require additional, material expenditures.

       Legal Matters

          Various  lawsuits,  claims and  proceedings  related  to CEI's  normal
business  operations are pending against CEI, the most  significant of which are
described herein.

          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
plant.  FirstEnergy is unable to predict the outcome of this  investigation.  In
addition,  FENOC remains subject to possible civil enforcement action by the NRC
in  connection  with the  events  leading  to the  Davis-Besse  outage  in 2002.
Further,  a  petition  was  filed  with  the NRC on  March  29,  2004 by a group
objecting to the NRC's restart order of the  Davis-Besse  Nuclear Power Station.
The Petition seeks among other things,  suspension of the Davis-Besse  operating
license.  If it were ultimately  determined that FirstEnergy has legal liability
or is  otherwise  made subject to  enforcement  action based on any of the above
matters with respect to the Davis-Besse outage, it could have a material adverse
effect on CEI's financial condition and results of operations.

          Legal  proceedings  have been filed against  FirstEnergy in connection
with, among other things, the restatements in August 2003 by FirstEnergy and its
Ohio utility  subsidiaries of previously reported results, the August 14th power
outage described above, and the extended outage at the Davis-Besse Nuclear Power
Station.  Depending  upon the particular  proceeding,  the issues raised include
alleged  violations of federal  securities  laws,  breaches of fiduciary  duties
under state law by FirstEnergy  directors and officers,  and damages as a result
of one or more of the noted events.  The securities cases have been consolidated
into one action pending in federal court in Akron,  Ohio. The derivative actions
filed in federal court  likewise have been  consolidated  as a separate  matter,
also in federal  court in Akron.  There are also pending  derivative  actions in
state court.

                                       73

<PAGE>

          FirstEnergy's Ohio utility subsidiaries were also named as respondents
in two  regulatory  proceedings  initiated at the PUCO in response to complaints
alleging failure to provide  reasonable and adequate service stemming  primarily
from the August 14th power outage.  FirstEnergy  is vigorously  defending  these
actions,  but cannot predict the outcome of any of these  proceedings or whether
any further  regulatory  proceedings or legal actions may be instituted  against
them. In particular,  if FirstEnergy  were  ultimately  determined to have legal
liability in connection with these proceedings, it could have a material adverse
effect on CEI's financial condition and results of operations.

          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  outage.  All three cases were
dismissed  for lack of  jurisdiction.  One case was  refiled at the PUCO and the
other two have been appealed.

Critical Accounting Policies

          CEI prepares its consolidated  financial statements in accordance with
GAAP.  Application of these principles often requires a high degree of judgment,
estimates and assumptions that affect financial results. All of CEI's assets are
subject to their own specific risks and uncertainties and are regularly reviewed
for  impairment.  Assets related to the  application  of the policies  discussed
below are similarly reviewed with their risks and uncertainties reflecting these
specific  factors.  CEI's more  significant  accounting  policies are  described
below.

       Regulatory Accounting

          CEI is  subject  to  regulation  that sets the  prices  (rates)  it is
permitted to charge its customers  based on costs that the  regulatory  agencies
determine CEI is permitted to recover.  At times,  regulators  permit the future
recovery through rates of costs that would be currently charged to expense by an
unregulated  company.  This  rate-making  process  results in the  recording  of
regulatory assets based on anticipated  future cash inflows.  As a result of the
changing regulatory framework in Ohio, a significant amount of regulatory assets
have been recorded - $1.02 billion as of March 31, 2004.  CEI regularly  reviews
these  assets  to assess  their  ultimate  recoverability  within  the  approved
regulatory  guidelines.  Impairment risk associated with these assets relates to
potentially adverse legislative, judicial or regulatory actions in the future.

       Revenue Recognition

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

       Pension and Other Postretirement Benefits Accounting

          FirstEnergy's  reported  costs of providing  non-contributory  defined
pension benefits and  postemployment  benefits other than pensions are dependent
upon  numerous  factors  resulting  from  actual  plan  experience  and  certain
assumptions.

          Pension  and  OPEB  costs  are   affected  by  employee   demographics
(including  age,  compensation  levels,  and employment  periods),  the level of
contributions  FirstEnergy makes to the plans, and earnings on plan assets. Such
factors may be further affected by business  combinations (such as FirstEnergy's
merger with GPU in November 2001),  which impacts  employee  demographics,  plan
experience  and other  factors.  Pension  and OPEB  costs are also  affected  by
changes  to key  assumptions,  including  anticipated  rates of  return  on plan
assets,  the discount rates and health care trend rates used in determining  the
projected benefit obligations for pension and OPEB costs.

          In accordance  with SFAS 87 and SFAS 106,  changes in pension and OPEB
obligations  associated with these factors may not be immediately  recognized as
costs on the income statement, but generally are recognized in future years over
the remaining average service period of plan participants.  SFAS 87 and SFAS 106
delay  recognition  of changes due to the  long-term  nature of pension and OPEB
obligations and the varying market  conditions likely to occur over long periods
of time. As such, significant portions of pension and OPEB costs recorded in any
period  may not  reflect  the actual  level of cash  benefits  provided  to plan
participants and are significantly influenced by assumptions about future market
conditions and plan participants' experience.

          In selecting an assumed discount rate, FirstEnergy considers currently
available rates of return on high-quality fixed income  investments  expected to
be   available   during  the  period  to  maturity  of  the  pension  and  other
postretirement  benefit  obligations.  Due to recent  declines in corporate bond

                                       74

<PAGE>

yields and interest rates in general,  FirstEnergy  reduced the assumed discount
rate as of December 31, 2003 to 6.25% from 6.75% used as of December 31, 2002.

          FirstEnergy's  assumed rate of return on pension plan assets considers
historical  market  returns and economic  forecasts for the types of investments
held by its pension trusts.  In 2003 and 2002, plan assets actually earned 24.0%
and (11.3)%,  respectively.  FirstEnergy's  pension  costs in 2003 and the first
quarter  of 2004 were  computed  assuming  a 9.0% rate of return on plan  assets
based upon  projections  of future  returns  and its  pension  trust  investment
allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash.

          Based on pension  assumptions  and pension  plan assets as of December
31, 2003,  FirstEnergy  will not be required to fund its pension  plans in 2004.
However,  health care cost trends have  significantly  increased and will affect
future  OPEB  costs.  The  2004  and  2003  composite  health  care  trend  rate
assumptions are approximately 10%-12% gradually decreasing to 5% in later years.
In determining  its trend rate  assumptions,  FirstEnergy  included the specific
provisions of its health care plans, the  demographics and utilization  rates of
plan participants,  actual cost increases  experienced in its health care plans,
and projections of future medical trend rates.

       Ohio Transition Cost Amortization

          In connection with FirstEnergy's  transition plan, the PUCO determined
allowable  transition costs based on amounts recorded on CEI's regulatory books.
These costs  exceeded  those  deferred or  capitalized  on CEI's  balance  sheet
prepared  under GAAP since they  included  certain costs which have not yet been
incurred or that were recognized on the regulatory  financial  statements  (fair
value purchase  accounting  adjustments).  CEI uses an effective interest method
for  amortizing its transition  costs,  often referred to as a  "mortgage-style"
amortization. The interest rate under this method is equal to the rate of return
authorized  by the  PUCO in the  transition  plan  for  CEI.  In  computing  the
transition  cost  amortization,  CEI includes only the portion of the transition
revenues associated with transition costs included on the balance sheet prepared
under GAAP.  Revenues  collected  for the off balance sheet costs and the return
associated with these costs are recognized as income when received.

       Long-Lived Assets

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

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

       Nuclear Decommissioning

          In  accordance  with SFAS 143,  CEI  recognizes  an ARO for the future
decommissioning  of its nuclear  power plants.  The ARO liability  represents an
estimate  of the fair  value of CEI's  current  obligation  related  to  nuclear
decommissioning  and the  retirement of other assets.  A fair value  measurement
inherently  involves  uncertainty  in the amount and timing of settlement of the
liability.  CEI used an  expected  cash  flow  approach  (as  discussed  in FASB
Concepts   Statement   No.  7)  to  measure   the  fair  value  of  the  nuclear
decommissioning  ARO. This approach applies probability  weighting to discounted
future  cash flow  scenarios  that  reflect a range of  possible  outcomes.  The
scenarios consider  settlement of the ARO at the expiration of the nuclear power
plants' current license and settlement based on an extended license term.

       Goodwill

          In a business  combination,  the excess of the purchase price over the
estimated  fair  values  of the  assets  acquired  and  liabilities  assumed  is
recognized  as  goodwill.  Based  on the  guidance  provided  by SFAS  142,  CEI
evaluates  goodwill  for  impairment  at least  annually  and would make such an
evaluation  more  frequently  if  indicators  of  impairment  should  arise.  In
accordance with the accounting  standard,  if the fair value of a reporting unit
is less than its carrying value (including goodwill), the goodwill is tested for
impairment.  If  impairment  were to be indicated  CEI would  recognize a loss -
calculated as the difference  between the implied fair value of its goodwill and
the carrying  value of the  goodwill.  CEI's annual  review was completed in the
third quarter of 2003, with no impairment of goodwill  indicated.  The forecasts
used in CEI's  evaluations of goodwill  reflect  operations  consistent with its
general business  assumptions.  Unanticipated changes in those assumptions could
have a significant effect on CEI's future  evaluations of goodwill.  As of March
31, 2004, CEI had $1.7 billion of goodwill.

                                       75

<PAGE>

New Accounting Standards and Interpretations
--------------------------------------------

       FSP  106-1,  "Accounting  and  Disclosure  Requirements  Related  to  the
       Medicare Prescription Drug, Improvement and Modernization Act of 2003"

          Issued   January  12,  2004,   FSP  106-1   permits  a  sponsor  of  a
postretirement  health care plan that  provides a  prescription  drug benefit to
make a one-time  election to defer  accounting  for the effects of the  Medicare
Act.  FirstEnergy  elected to defer the effects of the  Medicare  Act due to the
lack of specific guidance.  Pursuant to FSP 106-1,  FirstEnergy began accounting
for the effects of the Medicare Act  effective  January 1, 2004 as a result of a
February  2, 2004 plan  amendment  that  required  remeasurement  of the  plan's
obligations.  See Note 2 for a discussion  of the effect of the federal  subsidy
and plan amendment on the consolidated financial statements.

       FIN 46 (revised  December  2003),  "Consolidation  of  Variable  Interest
       Entities"

          In  December  2003,  the  FASB  issued  a  revised  interpretation  of
Accounting  Research  Bulletin  No.  51,  "Consolidated  Financial  Statements",
referred  to as  FIN  46R,  which  requires  the  consolidation  of a VIE  by an
enterprise if that enterprise is determined to be the primary beneficiary of the
VIE. As required, CEI adopted FIN 46R for interests in VIEs commonly referred to
as special-purpose  entities effective December 31, 2003 and for all other types
of  entities  effective  March  31,  2004.  Adoption  of FIN 46R did not  have a
material  impact on CEI's  financial  statements for the quarter ended March 31,
2004. See Note 2 for a discussion of Variable Interest Entities.

                                       76

<PAGE>

<TABLE>


                                           THE TOLEDO EDISON COMPANY

                                       CONSOLIDATED STATEMENTS OF INCOME
                                                  (Unaudited)


<CAPTION>
                                                                                          Three Months Ended
                                                                                                March 31,
                                                                                       -------------------------
                                                                                         2004             2003
                                                                                       --------         --------
                                                                                                        Restated
                                                                                                      (See Note 2)
                                                                                             (In thousands)

<S>                                                                                    <C>              <C>
OPERATING REVENUES..............................................................       $235,398         $231,822
                                                                                       --------         --------


OPERATING EXPENSES AND TAXES:
   Fuel.........................................................................         10,214            8,406
   Purchased power..............................................................         82,408           74,251
   Nuclear operating costs......................................................         42,692           64,555
   Other operating costs........................................................         36,208           32,932
                                                                                       --------         --------
       Total operation and maintenance expenses.................................        171,522          180,144
   Provision for depreciation and amortization..................................         40,689           35,640
   General taxes................................................................         14,300           15,008
   Income taxes (benefit).......................................................         (1,578)          (4,291)
                                                                                       --------         --------
       Total operating expenses and taxes.......................................        224,933          226,501
                                                                                       --------         --------


OPERATING INCOME................................................................         10,465            5,321
                                                                                       --------         --------


OTHER INCOME....................................................................          5,833            3,100
                                                                                       --------         --------


INCOME BEFORE NET INTEREST CHARGES..............................................         16,298            8,421
                                                                                       --------         --------


NET INTEREST CHARGES:
   Interest on long-term debt...................................................          9,461           10,888
   Allowance for borrowed funds used during construction........................         (1,400)          (1,306)
   Other interest expense (credit)..............................................            706             (532)
                                                                                       --------         --------
       Net interest charges.....................................................          8,767            9,050
                                                                                       --------         --------


INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE.....................          7,531             (629)

Cumulative effect of accounting change (net of income taxes
   of $18,201,000) (Note 2).....................................................             --           25,550
                                                                                       --------         --------


NET INCOME......................................................................          7,531           24,921


PREFERRED STOCK DIVIDEND REQUIREMENTS...........................................          2,211            2,205
                                                                                       --------         --------


EARNINGS ON COMMON STOCK........................................................       $  5,320         $ 22,716
                                                                                       ========         ========


<FN>
The preceding Notes to Consolidated Financial Statements as they relate to The
Toledo Edison Company are an integral part of these statements.
</FN>

                                                      77

</TABLE>

<PAGE>

<TABLE>

                                           THE TOLEDO EDISON COMPANY

                                          CONSOLIDATED BALANCE SHEETS
                                                  (Unaudited)

<CAPTION>
                                                                                        March 31,       December 31,
                                                                                          2004             2003
                                                                                      ------------------------------
                                                                                              (In thousands)
                                         ASSETS

UTILITY PLANT:
<S>                                                                                    <C>              <C>
   In service....................................................................      $1,801,162       $1,714,870
   Less-Accumulated provision for depreciation...................................         733,161          721,754
                                                                                       ----------       ----------
                                                                                        1,068,001          993,116
                                                                                       ----------       ----------
   Construction work in progress-
     Electric plant..............................................................          66,499          125,051
     Nuclear fuel................................................................              --           20,189
                                                                                       ----------       ----------
                                                                                           66,499          145,240
                                                                                       ----------       ----------
                                                                                        1,134,500        1,138,356
OTHER PROPERTY AND INVESTMENTS:
   Investment in lessor notes....................................................         190,658          200,938
   Nuclear plant decommissioning trusts..........................................         255,996          240,634
   Long-term notes receivable from associated companies..........................         163,961          163,626
   Other.........................................................................           2,326            2,119
                                                                                       ----------       ----------
                                                                                          612,941          607,317
                                                                                       ----------       ----------
CURRENT ASSETS:
   Cash and cash equivalents.....................................................              16            2,237
   Receivables-
     Customers...................................................................           4,876            4,083
     Associated companies........................................................          21,982           29,158
     Other.......................................................................             734           14,386
   Notes receivable from associated companies....................................          16,376           19,316
   Materials and supplies, at average cost.......................................          36,581           35,147
   Prepayments and other........................................................            3,320            6,704
                                                                                       ----------       ----------
                                                                                           83,885          111,031
                                                                                       ----------       ----------
DEFERRED CHARGES:
   Regulatory assets.............................................................         432,399          459,040
   Goodwill......................................................................         504,522          504,522
   Property taxes................................................................          24,443           24,443
   Other.........................................................................          10,902           10,689
                                                                                       ----------       ----------
                                                                                          972,266          998,694
                                                                                       ----------       ----------
                                                                                       $2,803,592       $2,855,398
                                                                                       ==========       ==========

                           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       $  195,670
     Other paid-in capital.......................................................         428,559          428,559
     Accumulated other comprehensive income......................................          15,023           11,672
     Retained earnings...........................................................         118,940          113,620
                                                                                       ----------       ----------
       Total common stockholder's equity.........................................         758,192          749,521
   Preferred stock not subject to mandatory redemption...........................         126,000          126,000
   Long-term debt................................................................         274,595          270,072
                                                                                       ----------       ----------
                                                                                        1,158,787        1,145,593
CURRENT LIABILITIES:
   Currently payable long-term debt..............................................         335,950          283,650
   Short-term borrowings.........................................................              --           70,000
   Accounts payable-
     Associated companies........................................................         126,835          132,876
     Other.......................................................................           2,784            2,816
   Notes payable to associated companies.........................................         262,654          285,953
   Accrued  taxes................................................................          41,518           55,604
   Accrued interest..............................................................          10,132           12,412
   Lease market valuation liability..............................................          24,600           24,600
   Other.........................................................................          46,771           37,299
                                                                                       ----------       ----------
                                                                                          851,244          905,210
                                                                                       ----------       ----------
NONCURRENT LIABILITIES:
   Accumulated deferred income taxes.............................................         204,108          201,954
   Accumulated deferred investment tax credits...................................          26,668           27,200
   Retirement benefits...........................................................          49,291           47,006
   Asset retirement obligation...................................................         184,882          181,839
   Lease market valuation liability..............................................         286,450          292,600
   Other.........................................................................          42,162           53,996
                                                                                       ----------       ----------
                                                                                          793,561          804,595
                                                                                       ----------       ----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 3)...............................
                                                                                       ----------       ----------
                                                                                       $2,803,592       $2,855,398
                                                                                       ==========       ==========


<FN>
The preceding  Notes to Consolidated  Financial  Statements as they relate to The Toledo Edison Company are an
integral part of these balance sheets.
</FN>

                                                      78

</TABLE>

<PAGE>

<TABLE>

                                           THE TOLEDO EDISON COMPANY

                                     CONSOLIDATED STATEMENTS OF CASH FLOWS
                                                  (Unaudited)


<CAPTION>
                                                                                        Three Months Ended
                                                                                              March 31,
                                                                                     --------------------------
                                                                                      2004               2003
                                                                                     --------          --------
                                                                                                       Restated
                                                                                                     (See Note 2)
                                                                                            (In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
<S>                                                                                  <C>              <C>
Net income......................................................................     $  7,531         $  24,921
   Adjustments to reconcile net income to net
     cash from operating activities-
       Provision for depreciation and amortization..............................       40,689            35,640
       Nuclear fuel and capital lease amortization..............................        5,506             2,768
       Deferred operating lease costs, net......................................       (7,692)           (7,672)
       Deferred income taxes, net...............................................       (1,499)           19,130
       Amortization of investment tax credits...................................         (532)             (514)
       Accrued retirement benefit obligation....................................        2,285               771
       Accrued compensation, net................................................         (733)           (1,865)
       Cumulative effect of accounting change (Note 2)..........................           --           (43,751)
       Receivables..............................................................       20,035            12,249
       Materials and supplies...................................................       (1,434)             (727)
       Accounts payable.........................................................       (6,074)          (53,917)
       Accrued taxes............................................................      (14,085)            6,281
       Accrued interest.........................................................       (2,280)           (2,326)
       Prepayments and other current assets.....................................        3,384            (5,121)
       Other....................................................................           79           (15,438)
                                                                                     --------          --------
         Net cash provided from (used for) operating activities.................       45,180           (29,571)
                                                                                     --------          --------

CASH FLOWS FROM FINANCING ACTIVITIES:
   New Financing-
     Long-term debt.............................................................       73,000                --
     Short-term borrowings, net.................................................           --            98,392
   Redemptions and Repayments-
     Long-term debt.............................................................      (15,000)          (73,600)
     Short-term borrowings, net.................................................      (93,299)               --
   Dividend Payments-
     Preferred stock............................................................       (2,211)           (2,211)
                                                                                     --------          --------
         Net cash provided from (used for) financing activities.................      (37,510)           22,581
                                                                                     --------          --------

CASH FLOWS FROM INVESTING ACTIVITIES:
   Property additions...........................................................       (8,440)          (17,622)
   Loans from (to) associated companies, net....................................        2,606            (4,445)
   Investment in lessor notes...................................................       10,280            17,628
   Contributions to nuclear decommissioning trust...............................       (7,135)           (7,135)
   Other........................................................................       (7,202)             (679)
                                                                                     --------          --------
         Net cash used for investing activities.................................       (9,891)          (12,253)
                                                                                     --------          --------

Net decrease in cash and equivalents............................................       (2,221)          (19,243)
Cash and cash equivalents at beginning of period................................        2,237            20,688
                                                                                     --------          --------
Cash and cash equivalents at end of period......................................     $     16          $  1,445
                                                                                     ========          ========


<FN>
The preceding  Notes to Consolidated  Financial  Statements as they relate to The Toledo Edison Company are an
integral part of these statements.
</FN>

                                                      79

</TABLE>

<PAGE>


                        REPORT OF INDEPENDENT ACCOUNTANTS


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,  2004,  and the  related
consolidated  statements  of income and cash  flows for each of the  three-month
periods ended March 31, 2004 and 2003.  These interim  financial  statements are
the responsibility of the Company's management.

We conducted our review in accordance with standards established by the American
Institute  of  Certified  Public  Accountants.  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 generally
accepted  auditing  standards,  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.

As discussed in Note 2 to the consolidated interim financial statements, the
Company has restated its previously issued consolidated interim financial
statements for the three-month period ended March 31, 2003.

We previously audited in accordance with auditing  standards  generally accepted
in the  United  States  of  America,  the  consolidated  balance  sheet  and the
consolidated  statement  of  capitalization  as of December  31,  2003,  and the
related  consolidated   statements  of  income,   common  stockholder's  equity,
preferred  stock,  cash flows and taxes for the year then  ended (not  presented
herein),  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 1(F) 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 February 25, 2004, we expressed
an  unqualified  opinion  on those  consolidated  financial  statements.  In our
opinion,  the information set forth in the accompanying  condensed  consolidated
balance sheet as of December 31, 2003, 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 7, 2004

                                       80

<PAGE>


                            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 them as their power  supplier.  TE provides power directly to
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. Power supply requirements of
TE are provided by FES -- an affiliated company.

Restatements of Previously Reported Quarterly Results
-----------------------------------------------------

          As discussed in Note 2 to the Consolidated Financial Statements,  TE's
quarterly  results for the first  quarter of 2003 have been  restated to correct
the amounts  reported for operating  expenses and interest  charges.  TE's costs
which were  originally  recorded  as  operating  expenses  and should  have been
capitalized to construction were $0.4 million ($0.2 million  after-tax),  in the
first quarter of 2003. In addition, TE's interest expense was overstated by $0.9
million  ($0.5 million  after-tax)  in the first quarter of 2003.  The impact of
these  adjustments  was not  material  to TE's  Consolidated  Balance  Sheets or
Consolidated Statements of Cash Flows for any quarter of 2003.

Results of Operations
---------------------

          Earnings on common stock in the first quarter of 2004  decreased to $5
million from $23 million in the first quarter of 2003.  Earnings on common stock
in the first  quarter of 2003  included an after-tax  credit of $26 million from
the cumulative  effect of an accounting  change due to the adoption of SFAS 143.
Income before the cumulative effect increased to $8 million in the first quarter
of 2004 from a loss of $629,000 in the first quarter of 2003.

          Operating  revenues  increased  by $4  million  or 1.5%  in the  first
quarter of 2004 from the same period in 2003.  Higher revenues  resulted from an
$11 million (20.3%)  increase in wholesale sales partially  offset by a decrease
in  retail  sales  revenues.  The  increase  in sales  revenues  from  wholesale
customers  (primarily  to FES) was due to increased  fossil  generation  (at the
Mansfield  Plant)  available  for  sale to  FES.  Electric  generation  services
provided by alternative  suppliers as a percent of total sales delivered in TE's
franchise  area  increased to 23.7% in the first quarter of 2004 from 22% in the
first quarter of 2003,  resulting in a 4.0%  decrease in TE's retail  generation
sales and a $3 million reduction in revenues.

          Distribution  deliveries  decreased  1.8% in the first quarter of 2004
compared  to  the  corresponding  quarter  of  2003,  with  an  increase  in the
industrial customer sector more than offset by reductions in the residential and
commercial   customer  sectors.   The  $3  million  decrease  in  revenues  from
electricity throughput in the first quarter of 2004 from the same quarter of the
prior  year  was  due  to  lower  composite  prices  and  reduced   distribution
deliveries.

          Under the Ohio transition plan, TE provides incentives to customers to
encourage  switching to alternative  energy providers.  These revenue reductions
are deferred for future recovery under the transition plan and do not materially
affect current period earnings.  The change in revenue from shopping credits was
relatively  flat in the first quarter of 2004  compared  with the  corresponding
period of 2003.

          Changes in electric  generation sales and  distribution  deliveries in
the first quarter of 2004 from the first  quarter of 2003 are  summarized in the
following table:


          Changes in Kilowatt-Hour Sales
          ----------------------------------------------------
          Increase (Decrease)
          Electric Generation:
              Retail................................    (4.0)%
              Wholesale.............................    21.9%
          ----------------------------------------------------
          Total Electric Generation Sales...........     6.5%
          ====================================================

          Distribution Deliveries:
            Residential.............................    (5.0)%
            Commercial..............................    (3.6)%
            Industrial..............................     1.2%
          ----------------------------------------------------
          Total Distribution Deliveries.............    (1.8)%
          ====================================================

                                       81

<PAGE>

       Operating Expenses and Taxes

          Total  operating  expenses  and taxes  decreased  by $2 million in the
first  quarter  of 2004 from the first  quarter  of 2003.  The  following  table
presents changes from the prior year by expense category.

          Operating Expenses and Taxes - Changes
          -----------------------------------------------------------------
           Increase (Decrease)                                 (In millions)
          Fuel.............................................        $ 2
          Purchased power..................................          8
          Nuclear operating costs..........................        (22)
          Other operating costs............................          3
          ------------------------------------------------------------
            Total operation and maintenance expenses.......         (9)

          Provision for depreciation and amortization......          5
          General taxes....................................         (1)
          Income taxes.....................................          3
          ------------------------------------------------------------
            Total operating expenses and taxes.............        $(2)
          =============================================================

          Higher  fuel  costs in the first  quarter of 2004,  compared  with the
first quarter of 2003,  primarily  resulted from increased fossil generation (up
54%). Higher purchased power costs reflect additional  kilowatt-hours  purchased
and  higher  unit  costs.  Reductions  in nuclear  operating  costs in the first
quarter of 2004,  compared with the first quarter of 2003, were primarily due to
the reduction in incremental  costs associated with the Davis-Besse  outage (see
Davis-Besse  Restoration).  The increase in other  operating costs resulted from
higher energy delivery costs related to increased tree trimming activities.

          The increase in depreciation and amortization charges of $5 million in
the  first  quarter  of 2004,  compared  with the  first  quarter  of 2003,  was
primarily due to increased amortization of regulatory assets.

       Other Income

          Other  income  increased  by $3 million  in the first  quarter of 2004
compared to the same period of 2003  primarily  due to the absence of 2003 costs
related to closing Acme in Toledo, Ohio.

       Net Interest Charges

          Net interest charges continued to trend lower,  decreasing by $283,000
in the  first  quarter  of 2004  from the same  quarter  last  year,  reflecting
redemptions  and  refinancings  since the end of the first quarter of 2003. TE's
long-term  debt  redemptions of $15 million during the first quarter of 2004 are
expected to result in annualized savings of approximately $1 million.

       Cumulative Effect of Accounting Change

          Upon adoption of SFAS 143 in the first quarter of 2003, TE recorded an
after-tax credit to net income of $26 million.  The cumulative effect adjustment
for unrecognized depreciation, accretion offset by the reduction in the existing
decommissioning  liabilities and ceasing the accounting practice of depreciating
non-regulated  generation  assets  using a cost of removal  component  was a $44
million increase to income, or $26 million net of income taxes.

Capital Resources and Liquidity
-------------------------------

          TE's cash  requirements in 2004 for operating  expenses,  construction
expenditures,  scheduled debt  maturities and preferred  stock  redemptions  are
expected  to be  met  without  increasing  its  net  debt  and  preferred  stock
outstanding.  Available  borrowing  capacity under short-term  credit facilities
will be used to manage working capital requirements.  Over the next three years,
TE  expects  to meet its  contractual  obligations  with cash  from  operations.
Thereafter,  TE expects to use a combination  of cash from  operations and funds
from the capital markets.

       Changes in Cash Position

          As of March 31, 2004,  TE had  approximately  $16,000 of cash and cash
equivalents, compared with $2 million as of December 31, 2003. The major sources
for changes in these balances are summarized below.

       Cash Flows From Operating Activities

          Cash provided from  operating  activities  during the first quarter of
2004, compared with the first quarter of 2003 were as follows:

                                       82

<PAGE>

          Operating Cash Flows                     2004          2003
          -------------------------------------------------------------
                                                      (In millions)

          Cash earnings (1)....................     $ 45         $ 29
          Working capital and other............       --          (59)
          -------------------------------------------------------------

          Total................................      $45         $(30)
          =============================================================

          (1)  Includes net income, depreciation and amortization, deferred
               operating lease costs, deferred income taxes, investment tax
               credits and major noncash charges.

          Net cash provided from operating  activities  increased $75 million in
the first  quarter  of 2004 from the first  quarter of 2003 as a result of a $59
million  increase  from  working  capital  and other  changes  and a $16 million
increase in cash  earnings.  The largest  factor  contributing  to the change in
working capital was a $48 million change in accounts payable.  The increase from
the change in working  capital also  included  receiving $12 million in proceeds
from the settlement of TE's claim against NRG, Inc. for the  terminated  sale of
its Bay Shore Plant.

       Cash Flows From Financing Activities

          Net cash used for  financing  activities  was $38 million in the first
quarter of 2004 compared to $23 million  provided from  financing  activities in
the first quarter of 2003. The  repayments and  redemptions of debt in the first
quarter  of 2004  exceeded  proceeds  from  issuing  new  long-term  debt by $35
million. In the first quarter of 2003, short-term borrowings exceeded repayments
of long-term debt by $25 million.

          TE had $16 million of cash and temporary  investments  (which  include
short-term  notes  receivable  from  associated  companies)  and $263 million of
short-term  indebtedness  as of March 31, 2004. TE is currently  precluded  from
issuing first mortgage bonds or preferred stock based upon  applicable  earnings
coverage tests.

          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  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 2004 was 1.30%.

          TE's access to capital markets and costs of financing are dependent on
the ratings of its securities and that of our holding company,  FirstEnergy. The
ratings outlook on all of its securities is stable.

          On February 6, 2004, Moody's  downgraded  FirstEnergy senior unsecured
debt to Baa3 from Baa2 and downgraded  the senior secured debt of JCP&L,  Met-Ed
and Penelec to Baa1 from A2. Moody's also  downgraded the preferred stock rating
of JCP&L to Ba1 from Baa2 and the  senior  unsecured  rating of  Penelec to Baa2
from A2. The ratings of OE, CEI, TE and Penn were  confirmed.  Moody's said that
the  lower  ratings  were  prompted  by:  "1) high  consolidated  leverage  with
significant  holding company debt, 2) a degree of regulatory  uncertainty in the
service  territories in which the company  operates,  3) risks  associated  with
investigations of the causes of the August 2003 blackout, and related securities
litigation,  and 4) a  narrowing  of  the  ratings  range  for  the  FirstEnergy
operating utilities,  given the degree to which FirstEnergy increasingly manages
the utilities as a single system and the significant financial interrelationship
among the subsidiaries."

          On March 9, 2004, S&P stated that the NRC's permission for FirstEnergy
to restart the Davis-Besse nuclear plant was positive for credit quality because
it would positively affect cash flow by eliminating  replacement power costs and
"demonstrating   management's  ability  to  overcome  operational   challenges."
However, S&P did not change  FirstEnergy's  ratings or outlook because it stated
that financial performance still "significantly lags expectations and management
faces other operational hurdles."

       Cash Flows From Investing Activities

          Net cash used for  investing  activities  decreased  $2 million in the
first  quarter of 2004 from the first  quarter of 2003 and was  primarily due to
lower capital expenditures.

          During the last  three  quarters  of 2004,  capital  requirements  for
property  additions  are  expected to be about $42  million.  TE has  additional
requirements of approximately $215 million to meet sinking fund requirements for
preferred  stock and maturing  long-term  debt during the remainder of 2004. The
cash requirements are expected to be satisfied from internal cash and short-term
arrangements.

                                       83

<PAGE>

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, 2004,  the present value of these sale
and leaseback operating lease commitments, net of trust investments,  total $595
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 $68 million of
off-balance sheet financing as of March 31, 2004.

Equity Price Risk
-----------------

          Included  in  TE's  nuclear   decommissioning  trust  investments  are
marketable equity securities carried at their market value of approximately $156
million  and  $145  million  as  of  March  31,  2004  and  December  31,  2003,
respectively.  A hypothetical  10% decrease in prices quoted by stock  exchanges
would result in a $16 million reduction in fair value as of March 31, 2004.

Outlook
-------

          Beginning  in 2001,  TE's  customers  were able to 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.

       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  regulated   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, 2005.

          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. TE's regulatory
assets as of March 31, 2004 and December 2003 are $432 million and $459 million,
respectively.  All of TE's  regulatory  assets are  expected  to  continue to be
recovered under the provisions of the transition plan.

          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  megawatts  (MW) of low cost  supply  to  unaffiliated  alternative
suppliers who serve customers within its service area. TE's  competitive  retail
sales affiliate, FES, acts as an alternate supplier for a portion of the load in
its franchise area.

          On October 21, 2003, the Ohio EUOC filed an application  with the PUCO
to establish  generation service rates beginning January 1, 2006, in response to
expressed concerns by the PUCO about price and supply uncertainty  following the
end of the market development period. The filing included two options:

          o   A  competitive  auction,  which would  establish a price for
              generation that customers would be charged during the period
              covered by the auction, or

          o   A  Rate  Stabilization  Plan,  which  would  extend  current
              generation prices through 2008, ensuring adequate generation
              supply at stable  prices,  and  continuing  TE's  support of
              energy efficiency and economic development efforts.

          Under  the first  option,  an  auction  would be  conducted  to secure
generation  service for TE's customers.  Beginning in 2006,  customers would pay
market prices for generation as determined by the auction.

          Under the Rate Stabilization  Plan option,  customers would have price
and supply  stability  through  2008 - three years  beyond the end of the market
development period - as well as the benefits of a competitive  market.  Customer
benefits would include:  customer  savings by extending the current five percent
discount on generation  costs and other customer  credits;  maintaining  current
distribution  base  rates  through  2007;  market-based  auctions  that  may  be

                                       84

<PAGE>

conducted  annually to ensure that  customers pay the lowest  available  prices;
extension of TE's support of  energy-efficiency  programs and the  potential for
continuing the program to give  preferred  access to  nonaffiliated  entities to
generation  capacity if shopping drops below 20%. Under the proposed plan, TE is
requesting:

          o   Extension of the transition  cost  amortization  period from
              mid-2007 to mid-2008;

          o   Deferral  of  interest  costs  on the  accumulated  shopping
              incentives  and  other  cost  deferrals  as  new  regulatory
              assets; and

          o   Ability to initiate a request to increase  generation  rates
              under certain limited conditions.

          On January 7, 2004,  the PUCO staff filed  testimony  on the  proposed
rate plan  generally  supporting the Rate  Stabilization  Plan as opposed to the
competitive  auction proposal.  Hearings began on February 11, 2004. On February
23, 2004,  after  consideration  of PUCO Staff comments and testimony as well as
those  provided by some of the  intervening  parties,  FirstEnergy  made certain
modifications  to the Rate  Stabilization  Plan. Oral arguments were held before
the PUCO on April 21 and a decision is  expected  from the PUCO in the Spring of
2004.

       Reliability Initiatives

          On  October  15,  2003,  NERC  issued a Near  Term  Action  Plan  that
contained  recommendations  for all control areas and  reliability  coordinators
with  respect  to  enhancing  system   reliability.   Approximately  20  of  the
recommendations  were directed at the FirstEnergy  companies and broadly focused
on  initiatives  that are  recommended  for  completion  by summer  2004.  These
initiatives  principally  relate to  changes in voltage  criteria  and  reactive
resources  management;  operational  preparedness  and action  plans;  emergency
response   capabilities;   and,  preparedness  and  operating  center  training.
FirstEnergy   presented  a  detailed   compliance  plan  to  NERC,   which  NERC
subsequently  endorsed on May 7, 2004, and the various  initiatives are expected
to be completed no later than June 30, 2004.

          On February 26-27, 2004, certain FirstEnergy companies participated in
a NERC Control Area Readiness Audit. This audit, part of an announced program by
NERC to review  control area  operations  throughout  much of the United  States
during 2004, is an  independent  review to identify areas for  improvement.  The
final  audit  report was  completed  on April 30,  2004.  The report  identified
positive  observations  and included  various  recommendations  for improvement.
FirstEnergy  is currently  reviewing the audit results and  recommendations  and
expects to  implement  those  relating to summer  2004 by June 30.  Based on its
review thus far, FirstEnergy believes that none of the recommendations  identify
a  need  for  any  incremental  material  investment  or  upgrades  to  existing
equipment.  FirstEnergy notes, however, that NERC 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.

          On March 1, 2004, certain  FirstEnergy  companies filed, in accordance
with a November 25, 2003 order from the PUCO, their plan for addressing  certain
issues  identified  by the PUCO from the U.S. - Canada Power System  Outage Task
Force  interim  report.  In  particular,   the  filing  addressed   upgrades  to
FirstEnergy's  control room computer  hardware and software and  enhancements to
the  training of control  room  operators.  The PUCO will review the plan before
determining the next steps, if any, in the proceeding.

          On April 22,  2004,  FirstEnergy  filed  with FERC the  results of the
FERC-ordered independent study of part of Ohio's power grid. The study examined,
among other things,  the reliability of the transmission grid in critical points
in  the  Northern  Ohio  area  and  the  need,   if  any,  for  reactive   power
reinforcements  during summer 2004 and 2005.  FirstEnergy is currently reviewing
the  results  of that  study and  expects  to  complete  the  implementation  of
recommendations  relating to 2004 by this summer.  Based on its review thus far,
FirstEnergy  believes that the study does not recommend any incremental material
investment or 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.

          With respect to each of the  foregoing  initiatives,  FirstEnergy  has
requested and NERC has agreed to provide, a technical assistance team of experts
to provide ongoing guidance and assistance in implementing and confirming timely
and successful completion.

                                       85

<PAGE>

       Davis-Besse Restoration

          On April 30, 2002,  the NRC initiated a formal  inspection  process at
the  Davis-Besse  nuclear plant.  This action was taken in response to corrosion
found by FENOC in the  reactor  vessel  head near the  nozzle  penetration  hole
during a  refueling  outage in the first  quarter  of 2002.  The  purpose of the
formal  inspection  process was to establish  criteria for NRC  oversight of the
licensee's  performance  and to  provide a record of the  major  regulatory  and
licensee actions taken,  and technical issues resolved.  This process led to the
NRC's March 8, 2004 approval of Davis-Besse's restart.

          Restart  activities  included both hardware and management  issues. In
addition  to  refurbishment  and  installation  work at the  plant,  FENOC  made
significant  management  and  human  performance  changes  with  the  intent  of
enhancing the proper  safety  culture  throughout  the  workforce.  The focus of
activities  in  the  first  quarter  of  2004  involved   management  and  human
performance issues. As a result,  incremental  maintenance costs declined in the
first quarter of 2004 compared to the same period in 2003 as emphasis shifted to
performance  issues;  however,  replacement power costs were higher in the first
quarter  of 2004.  The  plant's  generating  equipment  was  tested  in March in
preparation for resumption of operation.  On April 4, 2004,  Davis-Besse resumed
generating electricity at 100% power.

          Incremental  costs  associated  with the extended  Davis-Besse  outage
(TE's share - 48.62%) for the first quarter of 2004 and 2003 were as follows:

                                          Three Months Ended
                                              March 31,
                                         -------------------          Increase
 Costs of Davis-Besse Extended Outage    2004        2003            (Decrease)
 ------------------------------------------------------------------------------
                                                   (In millions)
 Incremental Expense
   Replacement power.................     $64            $52             $ 12
   Maintenance.......................       1             36              (35)
 -----------------------------------------------------------------------------
       Total.........................     $65            $88             $(23)
 =============================================================================

 Incremental Net of Tax Expense......     $38            $52             $(14)
 ==============================================================================


       Environmental Matters

          Various federal,  state and local authorities  regulate TE with regard
to air and water  quality  and  other  environmental  matters.  The  effects  of
compliance  on TE with  regard to  environmental  matters  could have a material
adverse effect on its earnings and  competitive  position.  These  environmental
regulations affect TE'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,  TE believes it is in material  compliance with
existing  regulations  but is  unable to  predict  future  change in  regulatory
policies and what, if any, the effects of such change would be.

          TE is required to meet federally approved SO2 regulations.  Violations
of such  regulations  can result in shutdown  of the  generating  unit  involved
and/or civil or criminal  penalties of up to $31,500 for each day the unit is in
violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio
that allows for compliance based on a 30-day averaging period. TE cannot predict
what  action  the EPA  may  take  in the  future  with  respect  to the  interim
enforcement policy.

          TE is complying  with SO2 reduction  requirements  under the Clean Air
Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity
from lower-emitting  plants,  and/or using emission  allowances.  NOx reductions
required by the 1990 Amendments are being achieved through  combustion  controls
and the generation of more electricity at  lower-emitting  plants.  In September
1998, the EPA finalized  regulations  requiring  additional NOx reductions  from
TE's Ohio and  Pennsylvania  facilities.  The EPA's NOx  Transport  Rule imposes
uniform  reductions of NOx emissions  (an  approximate  85% reduction in utility
plant NOx emissions from projected 2007  emissions)  across a region of nineteen
states (including Michigan,  New Jersey, Ohio and Pennsylvania) and the District
of Columbia  based on a  conclusion  that such NOx  emissions  are  contributing
significantly to ozone levels in the eastern United States. State Implementation
Plans  (SIP) must  comply by May 31,  2004 with  individual  state NOx  budgets.
Pennsylvania  submitted a SIP that required  compliance  with the NOx budgets at
TE's Pennsylvania  facilities by May 1, 2003. Ohio submitted a SIP that requires
compliance  with the NOx budgets at TE's Ohio  facilities by May 31, 2004.  TE's
facilities have complied with the NOx budgets in 2003 and 2004, respectively.

          TE 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 be held  liable  on a joint and  several  basis.  Therefore,  environmental
liabilities   that  are  considered   probable  have  been   recognized  on  the
Consolidated  Balance Sheets,  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. TE has  accrued  liabilities  aggregating

                                       86

<PAGE>

approximately  $0.2  million  as of March 31,  2004.  TE  accrues  environmental
liabilities only when it can conclude that it is probable that an obligation for
such  costs  exists  and can  reasonably  determine  the  amount of such  costs.
Unasserted   claims  are  reflected  in  TE's   determination  of  environmental
liabilities  and are  accrued  in the  period  that they are both  probable  and
reasonably estimable.

       Power Outage

          On August  14,  2003,  various  states  and parts of  southern  Canada
experienced a widespread power outage.  That outage affected  approximately  1.4
million  customers in  FirstEnergy's  service area.  On April 5, 2004,  the U.S.
-Canada Power System Outage Task Force released its final report on this outage.
The final report supercedes the interim report that had been issued in November,
2003. In the final report,  the Task Force concluded,  among other things,  that
the problems  leading to the outage began in  FirstEnergy's  Ohio service  area.
Specifically,   the  final  report  concludes,  among  other  things,  that  the
initiation of the August 14th power outage resulted from the coincidence on that
afternoon of several events,  including,  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 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 14th power outage and that it does not
adequately  address the  underlying  causes of the outage.  FirstEnergy  remains
convinced  that the outage  cannot be explained  by events on any one  utility's
system. The final report contains 46 "recommendations to prevent or minimize the
scope of future blackouts."  Forty-five of those recommendations relate to broad
industry  or policy  matters  while one  relates  to  activities  the Task Force
recommends be undertaken by FirstEnergy,  MISO,  PJM, and ECAR.  FirstEnergy has
undertaken  several  initiatives,  some prior to and some since the August  14th
power outage,  to enhance  reliability which are consistent with these and other
recommendations  and believes it will complete  those relating to summer 2004 by
June 30 (see  Reliability  Initiatives  above).  As  many of  these  initiatives
already were in process and budgeted in 2004,  FirstEnergy does not believe that
any  incremental  expenses  associated with  additional  initiatives  undertaken
during 2004 will have a material effect on its operations or financial  results.
First  Energy  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.

       Legal Matters

          Various  lawsuits,  claims  and  proceedings  related  to TE's  normal
business  operations are pending  against TE, the most  significant of which are
described herein.

          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
plant.  FirstEnergy is unable to predict the outcome of this  investigation.  In
addition,  FENOC remains subject to possible civil enforcement action by the NRC
in  connection  with the  events  leading  to the  Davis  Besse  outage in 2002.
Further,  a  petition  was  filed  with  the NRC on  March  29,  2004 by a group
objecting to the NRC's restart order of the  Davis-Besse  Nuclear Power Station.
The Petition seeks among other things,  suspension of the Davis-Besse  operating
license.  If it were ultimately  determined that FirstEnergy has legal liability
or is  otherwise  made subject to  enforcement  action based on any of the above
matters with respect to the Davis-Besse outage, it could have a material adverse
effect on TE's financial condition and results of operations.

          Legal  proceedings  have been filed against  FirstEnergy in connection
with, among other things, the restatements in August 2003 by FirstEnergy and its
Ohio utility  subsidiaries of previously reported results, the August 14th power
outage described above, and the extended outage at the Davis-Besse Nuclear Power
Station.  Depending  upon the particular  proceeding,  the issues raised include
alleged  violations of federal  securities  laws,  breaches of fiduciary  duties
under state law by FirstEnergy  directors and officers,  and damages as a result
of one or more of the noted events.  The securities cases have been consolidated
into one action pending in federal court in Akron,  Ohio. The derivative actions
filed in federal court  likewise have been  consolidated  as a separate  matter,
also in federal  court in Akron.  There are also pending  derivative  actions in
state court.

          FirstEnergy's Ohio utility subsidiaries were also named as respondents
in two  regulatory  proceedings  initiated at the PUCO in response to complaints
alleging failure to provide  reasonable and adequate service stemming  primarily
from the August 14th power outage.  FirstEnergy  is vigorously  defending  these
actions,  but cannot predict the outcome of any of these  proceedings or whether
any further  regulatory  proceedings or legal actions may be instituted  against
them. In particular,  if FirstEnergy  were  ultimately  determined to have legal
liability in connection with these proceedings, it could have a material adverse
effect on TE's financial condition and results of operations.

                                       87

<PAGE>

          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  outage.  All three cases were
dismissed  for lack of  jurisdiction.  One case was  refiled at the PUCO and the
other two have been appealed.

Critical Accounting Policies
----------------------------

          TE prepares its consolidated  financial  statements in accordance with
GAAP.  Application of these principles often requires a high degree of judgment,
estimates and assumptions that affect financial results.  All of TE's assets are
subject to their own specific risks and uncertainties and are regularly reviewed
for  impairment.  Assets related to the  application  of the policies  discussed
below are similarly reviewed with their risks and uncertainties reflecting these
specific factors. TE's more significant accounting policies are described below.

       Regulatory Accounting

          TE is  subject  to  regulation  that  sets the  prices  (rates)  it is
permitted to charge its customers  based on costs that the  regulatory  agencies
determine  TE is permitted to recover.  At times,  regulators  permit the future
recovery through rates of costs that would be currently charged to expense by an
unregulated  company.  This  rate-making  process  results in the  recording  of
regulatory assets based on anticipated  future cash inflows.  As a result of the
changing regulatory framework in Ohio, a significant amount of regulatory assets
have been  recorded - $432  million as of March 31, 2004.  TE regularly  reviews
these  assets  to assess  their  ultimate  recoverability  within  the  approved
regulatory  guidelines.  Impairment risk associated with these assets relates to
potentially adverse legislative, judicial or regulatory actions in the future.

       Revenue Recognition

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

       Pension and Other Postretirement Benefits Accounting

          FirstEnergy's  reported  costs of providing  non-contributory  defined
pension benefits and  postemployment  benefits other than pensions are dependent
upon  numerous  factors  resulting  from  actual  plan  experience  and  certain
assumptions.

          Pension  and  OPEB  costs  are   affected  by  employee   demographics
(including  age,  compensation  levels,  and employment  periods),  the level of
contributions  FirstEnergy makes to the plans, and earnings on plan assets. Such
factors may be further affected by business  combinations (such as FirstEnergy's
merger with GPU in November 2001),  which impacts  employee  demographics,  plan
experience  and other  factors.  Pension  and OPEB  costs are also  affected  by
changes  to key  assumptions,  including  anticipated  rates of  return  on plan
assets,  the discount rates and health care trend rates used in determining  the
projected benefit obligations for pension and OPEB costs.

          In accordance  with SFAS 87 and SFAS 106,  changes in pension and OPEB
obligations  associated with these factors may not be immediately  recognized as
costs on the income statement, but generally are recognized in future years over
the remaining average service period of plan participants.  SFAS 87 and SFAS 106
delay  recognition  of changes due to the  long-term  nature of pension and OPEB
obligations and the varying market  conditions likely to occur over long periods
of time. As such, significant portions of pension and OPEB costs recorded in any
period  may not  reflect  the actual  level of cash  benefits  provided  to plan
participants and are significantly influenced by assumptions about future market
conditions and plan participants' experience.

          In selecting an assumed discount rate, FirstEnergy considers currently
available rates of return on high-quality fixed income  investments  expected to
be   available   during  the  period  to  maturity  of  the  pension  and  other
postretirement  benefit  obligations.  Due to recent  declines in corporate bond
yields and interest rates in general,  FirstEnergy  reduced the assumed discount
rate as of December 31, 2003 to 6.25% from 6.75% used as of December 31, 2002.

          FirstEnergy's  assumed rate of return on pension plan assets considers
historical  market  returns and economic  forecasts for the types of investments
held by its pension trusts.  In 2003 and 2002, plan assets actually earned 24.0%
and (11.3)%,  respectively.  FirstEnergy's  pension  costs in 2003 and the first
quarter  of 2004 were  computed  assuming  a 9.0% rate of return on plan  assets

                                       88

<PAGE>

based upon  projections  of future  returns  and its  pension  trust  investment
allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash.

          Based on pension  assumptions  and pension  plan assets as of December
31, 2003,  FirstEnergy  will not be required to fund its pension  plans in 2004.
However,  health care cost trends have  significantly  increased and will affect
future  OPEB  costs.  The  2004  and  2003  composite  health  care  trend  rate
assumptions are approximately 10%-12% gradually decreasing to 5% in later years.
In determining  its trend rate  assumptions,  FirstEnergy  included the specific
provisions of its health care plans, the  demographics and utilization  rates of
plan participants,  actual cost increases  experienced in its health care plans,
and projections of future medical trend rates.

       Ohio Transition Cost Amortization

          In connection with FirstEnergy's  transition plan, the PUCO determined
allowable  transition costs based on amounts recorded on TE's regulatory  books.
These  costs  exceeded  those  deferred or  capitalized  on TE's  balance  sheet
prepared  under GAAP since they  included  certain costs which have not yet been
incurred or that were recognized on the regulatory  financial  statements  (fair
value purchase accounting adjustments). TE uses an effective interest method for
amortizing  its  transition  costs,  often  referred  to  as a  "mortgage-style"
amortization. The interest rate under this method is equal to the rate of return
authorized  by the  PUCO  in the  transition  plan  for  TE.  In  computing  the
transition  cost  amortization,  TE includes only the portion of the  transition
revenues associated with transition costs included on the balance sheet prepared
under GAAP.  Revenues  collected  for the off balance sheet costs and the return
associated with these costs are recognized as income when received.

       Long-Lived Assets

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

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

       Nuclear Decommissioning

          In  accordance  with SFAS 143,  TE  recognizes  an ARO for the  future
decommissioning  of its nuclear  power plants.  The ARO liability  represents an
estimate  of the fair  value  of TE's  current  obligation  related  to  nuclear
decommissioning  and the  retirement of other assets.  A fair value  measurement
inherently  involves  uncertainty  in the amount and timing of settlement of the
liability. TE used an expected cash flow approach (as discussed in FASB Concepts
Statement No. 7) to measure the fair value of the nuclear  decommissioning  ARO.
This  approach  applies  probability  weighting to  discounted  future cash flow
scenarios  that reflect a range of possible  outcomes.  The  scenarios  consider
settlement of the ARO at the  expiration  of the nuclear  power plants'  current
license and settlement based on an extended license term.

       Goodwill

          In a business  combination,  the excess of the purchase price over the
estimated  fair  values  of the  assets  acquired  and  liabilities  assumed  is
recognized as goodwill. Based on the guidance provided by SFAS 142, TE evaluates
goodwill for impairment at least annually and would make such an evaluation more
frequently  if indicators of  impairment  should arise.  In accordance  with the
accounting  standard,  if the fair  value of a  reporting  unit is less than its
carrying value (including goodwill),  the goodwill is tested for impairment.  If
impairment  were to be indicated,  TE would recognize a loss - calculated as the
difference between the implied fair value of its goodwill and the carrying value
of the goodwill.  TE's annual review was completed in the third quarter of 2003,
with no impairment of goodwill indicated. The forecasts used in TE's evaluations
of goodwill reflect operations consistent with its general business assumptions.
Unanticipated  changes in those assumptions  could have a significant  effect on
TE's future  evaluations of goodwill.  As of March 31, 2004, TE had $505 million
of goodwill.

                                       89

<PAGE>



New Accounting Standards and Interpretations

       FSP  106-1,  "Accounting  and  Disclosure  Requirements  Related  to  the
       Medicare Prescription Drug, Improvement and Modernization Act of 2003"

          Issued   January  12,  2004,   FSP  106-1   permits  a  sponsor  of  a
postretirement  health care plan that  provides a  prescription  drug benefit to
make a one-time  election to defer  accounting  for the effects of the  Medicare
Act.  FirstEnergy  elected to defer the effects of the  Medicare  Act due to the
lack of specific guidance.  Pursuant to FSP 106-1,  FirstEnergy began accounting
for the effects of the Medicare Act  effective  January 1, 2004 as a result of a
February  2, 2004 plan  amendment  that  required  remeasurement  of the  plan's
obligations.  See Note 2 for a discussion  of the effect of the federal  subsidy
and plan amendment on the consolidated financial statements.

       FIN 46 (revised  December  2003),  "Consolidation  of  Variable  Interest
       Entities"

          In  December  2003,  the  FASB  issued  a  revised  interpretation  of
Accounting  Research  Bulletin  No.  51,  "Consolidated  Financial  Statements",
referred  to as  FIN  46R,  which  requires  the  consolidation  of a VIE  by an
enterprise if that enterprise is determined to be the primary beneficiary of the
VIE. As required,  TE adopted FIN 46R for interests in VIEs commonly referred to
as special-purpose  entities effective December 31, 2003 and for all other types
of  entities  effective  March  31,  2004.  Adoption  of FIN 46R did not  have a
material  impact on TE's  financial  statements  for the quarter ended March 31,
2004. See Note 2 for a discussion of Variable Interest Entities.

                                       90

<PAGE>
<TABLE>
                                             PENNSYLVANIA POWER COMPANY

                                         CONSOLIDATED STATEMENTS OF INCOME
                                                    (Unaudited)

<CAPTION>
                                                                                          Three Months Ended
                                                                                                March 31,
                                                                                       -------------------------
                                                                                         2004             2003
                                                                                       ---------        --------
                                                                                             (In thousands)

<S>                                                                                    <C>              <C>
OPERATING REVENUES..............................................................       $142,623         $128,343
                                                                                       --------         --------


OPERATING EXPENSES AND TAXES:
   Fuel.........................................................................          6,206            4,713
   Purchased power..............................................................         48,508           44,066
   Nuclear operating costs......................................................         18,623           46,929
   Other operating costs........................................................         13,685           16,550
                                                                                       --------         --------
       Total operation and maintenance expenses.................................         87,022          112,258
   Provision for depreciation and amortization..................................         13,438           13,265
   General taxes................................................................          6,634            6,179
   Income taxes (benefit).......................................................         15,038           (1,479)
                                                                                       --------         --------
       Total operating expenses and taxes.......................................        122,132          130,223
                                                                                       --------         --------


OPERATING INCOME (LOSS).........................................................         20,491           (1,880)


OTHER INCOME....................................................................            982              561
                                                                                       --------         --------


INCOME (LOSS) BEFORE NET INTEREST CHARGES.......................................         21,473           (1,319)
                                                                                       --------         --------


NET INTEREST CHARGES:
   Interest expense.............................................................          2,725            4,064
   Allowance for borrowed funds used during construction........................           (922)            (629)
                                                                                       --------         --------
       Net interest charges.....................................................          1,803            3,435
                                                                                       --------         --------


INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE.....................         19,670           (4,754)

Cumulative effect of accounting change (net of income taxes of $7,532,000) (Note 2)          --           10,618
                                                                                       --------         --------


NET INCOME......................................................................         19,670            5,864


PREFERRED STOCK DIVIDEND REQUIREMENTS...........................................            640              912
                                                                                       --------         --------


EARNINGS ON COMMON STOCK........................................................       $ 19,030         $  4,952
                                                                                       ========         ========


<FN>
The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Power Company are an
integral part of these statements.
</FN>

                                                         91

</TABLE>

<PAGE>

<TABLE>

                                             PENNSYLVANIA POWER COMPANY

                                            CONSOLIDATED BALANCE SHEETS
                                                    (Unaudited)
<CAPTION>
                                                                                         March 31,      December 31,
                                                                                           2004            2003
                                                                                        ---------------------------
                                                                                              (In thousands)
                                    ASSETS
UTILITY PLANT:
<S>                                                                                      <C>              <C>
In service........................................................................       $820,643         $808,637
Less-Accumulated provision for depreciation.......................................        332,363          324,710
                                                                                         --------         --------
                                                                                          488,280          483,927
                                                                                         --------         --------
Construction work in progress-
   Electric plant.................................................................         69,521           68,091
   Nuclear fuel...................................................................            360              360
                                                                                         --------         --------
                                                                                           69,881           68,451
                                                                                         --------         --------
                                                                                          558,161          552,378
                                                                                         --------         --------

OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts .............................................        137,840          133,867
Long-term notes receivable from associated companies..............................         33,136           39,179
Other.............................................................................            836            2,195
                                                                                         --------         --------
                                                                                          171,812          175,241
                                                                                         --------         --------

CURRENT ASSETS:
Cash and cash equivalents.........................................................             40               40
Notes receivable from associated companies........................................          6,558              399
Receivables-
   Customers (less accumulated provisions of $816,000 and $769,000,
     respectively, for uncollectible accounts)....................................         46,129           44,861
   Associated companies...........................................................         24,492           24,965
   Other..........................................................................            466            1,047
Materials and supplies, at average cost...........................................         34,993           33,918
Prepayments.......................................................................         22,716            9,383
                                                                                         --------         --------
                                                                                          135,394          114,613
                                                                                         --------         --------

DEFERRED CHARGES:
Regulatory assets.................................................................         15,155           27,513
Other.............................................................................          9,348            9,634
                                                                                         --------         --------
                                                                                           24,503           37,147
                                                                                         --------         --------
                                                                                         $889,870         $879,379
                                                                                         ========         ========

                        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         $188,700
   Other paid-in capital..........................................................           (310)            (310)
   Accumulated other comprehensive loss...........................................        (11,783)         (11,783)
   Retained earnings..............................................................         65,209           54,179
                                                                                         --------         --------
       Total common stockholder's equity..........................................        241,816          230,786
Preferred stock not subject to mandatory redemption...............................         39,105           39,105
Long-term debt and other long-term obligations....................................        130,397          130,358
                                                                                         --------         --------
                                                                                          411,318          400,249
                                                                                         --------         --------
CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock..............................         52,224           93,474
Accounts payable-
   Associated companies...........................................................         43,895           40,172
   Other..........................................................................          1,311            1,294
Notes payable to associated companies.............................................         40,418           11,334
Accrued taxes.....................................................................         35,900           27,091
Accrued interest..................................................................          2,440            4,396
Other.............................................................................          9,557            8,444
                                                                                         --------         --------
                                                                                          185,745          186,205
                                                                                         --------         --------

NONCURRENT LIABILITIES:
Accumulated deferred income taxes.................................................         93,894           97,871
Accumulated deferred investment tax credits.......................................          3,443            3,516
Asset retirement obligation.......................................................        131,678          129,546
Retirement benefits...............................................................         55,830           54,057
Other.............................................................................          7,962            7,935
                                                                                         --------         --------
                                                                                          292,807          292,925
                                                                                         --------         --------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 3)................................
                                                                                         --------         --------
                                                                                         $889,870         $879,379
                                                                                         ========         ========

<FN>
The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Power Company are an
integral part of these balance sheets.
</FN>

                                                         92

</TABLE>

<PAGE>

<TABLE>

                                             PENNSYLVANIA POWER COMPANY

                                       CONSOLIDATED STATEMENTS OF CASH FLOWS
                                                    (Unaudited)

<CAPTION>
                                                                                        Three Months Ended
                                                                                              March 31,
                                                                                    ---------------------------
                                                                                      2004               2003
                                                                                    ---------          --------
                                                                                            (In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
<S>                                                                                 <C>                <C>
Net income......................................................................    $ 19,670           $  5,864
Adjustments to reconcile net income to net
   cash from operating activities-
     Provision for depreciation and amortization................................      13,438             13,265
     Nuclear fuel and lease amortization........................................       4,565              3,583
     Deferred income taxes, net.................................................      (1,231)             6,122
     Amortization of investment tax credits.....................................        (575)              (620)
     Cumulative effect of accounting change (Note 2)............................          --            (18,150)
     Receivables................................................................        (214)            17,262
     Materials and supplies.....................................................      (1,075)              (431)
     Accounts payable...........................................................       3,740             27,844
     Accrued taxes..............................................................       8,809              4,271
     Accrued interest...........................................................      (1,956)            (2,009)
     Prepayments and other current assets.......................................     (13,334)           (16,288)
     Asset retirement obligation, net...........................................       3,195               (980)
     Other......................................................................       3,237                600
                                                                                    --------           --------
         Net cash provided from operating activities............................      38,269             40,333
                                                                                    --------           --------


CASH FLOWS FROM FINANCING ACTIVITIES:
   New Financing-
     Short-term borrowings, net.................................................      29,084                 --
   Redemptions and Repayments-
     Long-term debt.............................................................     (42,302)               (16)
   Dividend Payments-
     Common stock...............................................................      (8,000)           (13,000)
     Preferred stock............................................................        (640)              (912)
                                                                                    --------           --------
         Net cash used for financing activities.................................     (21,858)           (13,928)
                                                                                    --------           --------


CASH FLOWS FROM INVESTING ACTIVITIES:
   Property additions...........................................................     (13,998)           (31,054)
   Contributions to nuclear decommissioning trusts..............................        (399)              (399)
   Loans from (to) associated companies, net....................................        (116)             4,921
   Other........................................................................      (1,898)               732
                                                                                    --------           --------
         Net cash used for investing activities.................................     (16,411)           (25,800)
                                                                                    --------           --------


Net change in cash and cash equivalents.........................................          --                605
Cash and cash equivalents at beginning of period................................          40              1,222
                                                                                    --------           --------
Cash and cash equivalents at end of period......................................    $     40           $  1,827
                                                                                    ========           ========


<FN>
The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Power Company are an
integral part of these statements.
</FN>

                                                         93

</TABLE>

<PAGE>


                        REPORT OF INDEPENDENT ACCOUNTANTS


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,  2004,  and  the  related
consolidated  statements  of income and cash  flows for each of the  three-month
periods ended March 31, 2004 and 2003.  These interim  financial  statements are
the responsibility of the Company's management.

We conducted our review in accordance with standards established by the American
Institute  of  Certified  Public  Accountants.  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 generally
accepted  auditing  standards,  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 auditing  standards  generally accepted
in the  United  States  of  America,  the  balance  sheet and the  statement  of
capitalization  as of December 31, 2003,  and the related  statements of income,
common stockholders' equity,  preferred stock, cash flows and taxes for the year
then ended (not presented herein), 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 1(E) to those  financial
statements)  dated  February 25, 2004,  we expressed an  unqualified  opinion on
those  financial  statements.  In our opinion,  the information set forth in the
accompanying  condensed  balance sheet as of December 31, 2003, is fairly stated
in all material respects in relation to the balance sheet from which it has been
derived.


PricewaterhouseCoopers LLP
Cleveland, Ohio
May 7, 2004

                                       94

<PAGE>


                           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 it 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.  Penn's  wholly owned  subsidiary,
Penn Power Funding LLC, began operations on March 30, 2004.

Results of Operations
---------------------

          Earnings on common stock in the first quarter of 2004 increased to $19
million from $5 million in the first  quarter of 2003.  Earnings on common stock
in the first  quarter of 2003  included an after-tax  credit of $11 million from
the cumulative  effect of an accounting  change due to the adoption of SFAS 143.
Income before the cumulative effect was $20 million in the first three months of
2004,  compared to a loss of $5 million  for the same  period of 2003.  Improved
results in the first quarter of 2004 reflect higher operating revenues and lower
operating expenses -- primarily nuclear operating costs.

          Operating  revenues  increased  by $14  million  or 11.1% in the first
quarter of 2004  compared  with the same  period in 2003.  The  higher  revenues
primarily  resulted  from  increased  wholesale  revenues  of $11 million due to
increased nuclear  generation  available for sale to FES in the first quarter of
2004. Retail sales revenues  increased $3 million primarily from a 3.1% increase
in generation sales.

          Distribution  deliveries  increased  3.1% in the first quarter of 2004
compared with the corresponding  quarter of 2003, with increases in all customer
sectors.  The change in revenues from  electricity  throughput was flat with the
effect of the volume increase offset by lower composite prices.

          Changes in electric  generation sales and  distribution  deliveries in
the first  quarter of 2004 from the same quarter of 2003 are  summarized  in the
following table:

                  Changes in Kilowatt-Hour Sales
                  ---------------------------------------------------
                  Increase (Decrease)
                  Electric Generation:
                    Retail..................................     3.1%
                    Wholesale...............................    32.1%
                  ---------------------------------------------------
                  Total Electric Generation Sales...........    18.3%
                  ===================================================
                  Distribution Deliveries:
                    Residential.............................     3.1%
                    Commercial..............................     0.5%
                    Industrial..............................     5.4%
                  ---------------------------------------------------
                  Total Distribution Deliveries.............     3.1%
                  ===================================================

       Operating Expenses and Taxes

          Total  operating  expenses  and taxes  decreased  by $8 million in the
first  quarter  of 2004 from the first  quarter  of 2003.  The  following  table
presents changes from the prior year by expense category.

                  Operating Expenses and Taxes - Changes
                  ------------------------------------------------------------
                  Increase (Decrease)                              (In millions)
                  Fuel............................................    $  2
                  Purchased power ................................       4
                  Nuclear operating costs.........................     (28)
                  Other operating costs...........................      (3)
                  ------------------------------------------------------------
                     Total operation and maintenance expenses.....     (25)
                  Provision for depreciation and amortization.....      --
                  General taxes...................................      --
                  Income taxes....................................      17
                  ------------------------------------------------------------
                     Total operating expenses and taxes...........    $ (8)
                  ============================================================

          Higher fuel costs in the first quarter of 2004, compared with the same
quarter of 2003,  resulted from increased  nuclear  generation.  Purchased power
costs were higher in the first three months of 2004  reflecting a 4.8%  increase

                                       95

<PAGE>

in kilowatt-hour  purchases and higher unit costs. Lower nuclear operating costs
occurred  in large  part due to the  absence  in 2004 of a  refueling  outage at
Beaver  Valley Unit 1. Beaver  Valley Unit 1 (65.00%  ownership)  experienced  a
refueling outage in the first quarter of 2003.

       Net Interest Charges

          Net  interest  charges   continued  to  trend  lower,   decreasing  by
approximately  $2 million in the first quarter of 2004 from the same period last
year,  reflecting  mandatory  and  optional  redemptions  of $83  million  total
principal amount of debt securities since the first quarter of 2003.

       Cumulative Effect of Accounting Change

          Upon adoption of SFAS 143 in the first quarter of 2003,  Penn recorded
an after-tax credit to net income of $11 million. The cumulative  adjustment for
unrecognized  depreciation,  accretion  offset by the  reduction in the existing
decommissioning  liabilities and ceasing the accounting practice of depreciating
non-regulated  generation  assets using a cost of removal  component  was an $18
million increase to income, or $11 million net of income taxes.

Capital Resources and Liquidity
-------------------------------

          Penn's cash requirements in 2004 for operating expenses,  construction
expenditures,  scheduled debt  maturities and preferred  stock  redemptions  are
expected  to be met  without  increasing  Penn's  net debt and  preferred  stock
outstanding.  Available  borrowing  capacity under short-term  credit facilities
will be used to manage working capital requirements.  Over the next three years,
Penn  expects to meet its  contractual  obligations  with cash from  operations.
Thereafter,  Penn expects to use a combination of cash from operations and funds
from the capital markets.

       Changes in Cash Position

          Penn had $40,000 of cash and cash equivalents as of March 31, 2004 and
December 31, 2003.

       Cash Flows From Operating Activities

          Cash provided from  operating  activities  during the first quarter of
2004, compared with the corresponding period in 2003 were as follows:


          Operating Cash Flows                       2004           2003
          -----------------------------------------------------------------
                                                         (In millions)
          Cash earnings (1)..................         $38            $11
          Working capital and other..........          --             29
          -----------------------------------------------------------------

          Total..............................         $38            $40
          =================================================================

          (1) Includes net income, depreciation and amortization,
              deferred income taxes, investment tax credits and major
              noncash charges.

          Net cash from  operating  activities  decreased  to $38 million in the
first  quarter of 2004 from $40  million in the same period of 2003 due to a $27
million  increase in cash  earnings  and a $29 million  reduction  from  working
capital and other changes  (primarily  change in accounts  payable to associated
companies).

       Cash Flows From Financing Activities

          In the first quarter of 2004,  net cash used for financing  activities
increased  to $22 million  from $14  million in the same  period last year.  The
increase resulted from increased long-term debt redemptions, partially offset by
increased short-term borrowings and reduced common stock dividends to OE.

          Penn had  approximately  $7 million of cash and temporary  investments
(which include  short-term notes  receivable from associated  companies) and $40
million of short-term  indebtedness  as of March 31, 2004.  Penn may borrow from
its  affiliates  on a short-term  basis.  Penn had the  capability to issue $500
million of additional  first mortgage  bonds on the basis of property  additions
and retired bonds.  Based upon applicable  earnings  coverage tests,  Penn could
issue up to $521 million of preferred  stock  (assuming no  additional  debt was
issued) as of March 31, 2004.

          In  March  2004,  Penn  completed  an  on-balance  sheet,   receivable
financing transaction which allows it to borrow up to $25 million. The borrowing
rate is based on bank commercial paper rates.  Penn is required to pay an annual
facility fee of 0.40% on the entire finance  limit.  The facility was undrawn as
of March 31, 2004. This facility matures on March 29, 2005.

                                       96

<PAGE>

          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 of its securities is stable.

          On February 6, 2004, Moody's  downgraded  FirstEnergy senior unsecured
debt to Baa3 from Baa2 and downgraded  the senior secured debt of JCP&L,  Met-Ed
and Penelec to Baa1 from A2. Moody's also  downgraded the preferred stock rating
of JCP&L to Ba1 from Baa2 and the  senior  unsecured  rating of  Penelec to Baa2
from A2. The ratings of OE, CEI, TE and Penn were  confirmed.  Moody's said that
the  lower  ratings  were  prompted  by:  "1) high  consolidated  leverage  with
significant  holding company debt, 2) a degree of regulatory  uncertainty in the
service  territories in which the company  operates,  3) risks  associated  with
investigations of the causes of the August 2003 blackout, and related securities
litigation,  and 4) a  narrowing  of  the  ratings  range  for  the  FirstEnergy
operating utilities,  given the degree to which FirstEnergy increasingly manages
the utilities as a single system and the significant financial interrelationship
among the subsidiaries."

          On March 9, 2004, S&P stated that the NRC's permission for FirstEnergy
to restart the Davis-Besse nuclear plant was positive for credit quality because
it would positively affect cash flow by eliminating  replacement power costs and
"demonstrating   management's  ability  to  overcome  operational   challenges."
However, S&P did not change  FirstEnergy's  ratings or outlook because it stated
that financial performance still "significantly lags expectations and management
faces other operational hurdles."

       Cash Flows From Investing Activities

          Net cash used for  investing  activities  totaled  $16  million in the
first quarter of 2004,  compared to $26 million for the same period of 2003. The
$10 million decrease in funds used for investing  activities  resulted primarily
from  lower  capital  expenditures  partially  offset  by  changes  in  loans to
associated companies.

          During the last  three  quarters  of 2004,  capital  requirements  for
property  additions  and capital  leases are  expected to be about $70  million,
including  $21 million for nuclear fuel.  Penn has  additional  requirements  of
approximately  $22 million to meet sinking fund requirements for preferred stock
and  maturing   long-term  debt  during  the  remainder  of  2004.   These  cash
requirements  are expected to be satisfied  from  internal  cash and  short-term
credit arrangements.

Equity Price Risk
-----------------

          Included  in Penn's  nuclear  decommissioning  trust  investments  are
marketable equity securities  carried at their market value of approximately $51
million  and  $50  million  as  of  March  31,  2004  and   December  31,  2003,
respectively.  A hypothetical  10% decrease in prices quoted by stock  exchanges
would result in a $5 million reduction in fair value as of March 31, 2004.

Outlook
-------

          Beginning in 1999,  Penn's  customers were able to select  alternative
energy  suppliers.  Penn  continues  to  deliver  power to homes and  businesses
through its existing  distribution  system,  which remains  regulated.  The PPUC
authorized Penn's rate  restructuring  plan,  establishing  separate charges for
transmission,  distribution,  generation  and stranded cost  recovery,  which is
recovered through a CTC.  Customers electing to obtain power from an alternative
supplier have their bills reduced based on the regulated  generation  component,
and the customers  receive a generation  charge from the  alternative  supplier.
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, which is referred to as its PLR obligation.

       Regulatory Matters

          As  part  of  Penn's   transition  plan  it  is  obligated  to  supply
electricity  to  customers  who do not choose an  alternative  supplier.  Penn's
competitive  retail sales  affiliate,  FES, acts as an alternate  supplier for a
portion of the load in its franchise area.

          In late 2003,  the PPUC  issued a  Tentative  Order  implementing  new
reliability  benchmarks  and  standards.  In  connection  therewith,   the  PPUC
commenced a  rulemaking  procedure  to amend the  Electric  Service  Reliability
Regulations to implement these new benchmarks,  and create additional  reporting
on  reliability.  Although  neither  the  Tentative  Order  nor the  Reliability
Rulemaking has been finalized,  the PPUC ordered all  Pennsylvania  utilities to
begin filing quarterly  reports on November 1, 2003. The comment period for both
the  Tentative  Order and the  Proposed  Rulemaking  Order has  closed.  Penn is
currently  awaiting the PPUC to issue a final order in both  matters.  The order

                                       97

<PAGE>

will  determine  (1) the standards  and  benchmarks to be utilized,  and (2) the
details required in the quarterly and annual reports.

          On January 16,  2004,  the PPUC  initiated a formal  investigation  of
whether Penn's "service  reliability  performance  deteriorated to a point below
the  level of  service  reliability  that  existed  prior to  restructuring"  in
Pennsylvania.  Discovery has commenced in the proceeding and Penn's testimony is
due May 14,  2004.  Hearings  are  scheduled  to begin  August  3,  2004 in this
investigation  and the ALJ has been directed to issue a Recommended  Decision by
September  30,  2004,  in order to allow the PPUC time to issue a Final Order by
year end of 2004. Penn is unable to predict the outcome of the  investigation or
the impact of the PPUC order.

          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.  All of Penn's
regulatory  assets are expected to continue to be recovered under the provisions
of its regulatory  plan.  Penn's  regulatory  assets totaled $15 million and $28
million as of March 31, 2004 and December 31, 2003, respectively.

       Environmental Matters

          Various federal, state and local authorities regulate Penn with regard
to air and water  quality  and  other  environmental  matters.  The  effects  of
compliance  on Penn with regard to  environmental  matters could have a material
adverse effect on its earnings and  competitive  position.  These  environmental
regulations  affect Penn'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,  Penn  believes  it is in material
compliance  with existing  regulations but is unable to predict future change in
regulatory policies and what, if any, the effects of such change would be.

          Penn  is  required  to  meet  federally   approved  SO2   regulations.
Violations of such  regulations  can result in shutdown of the  generating  unit
involved  and/or  civil or criminal  penalties of up to $31,500 for each day the
unit  is in  violation.  The  EPA  has an  interim  enforcement  policy  for SO2
regulations  in Ohio that  allows  for  compliance  based on a 30-day  averaging
period.  Penn  cannot  predict  what  action the EPA may take in the future with
respect to the interim enforcement policy.

          In 1999 and 2000,  the EPA  issued  Notices  of  Violation  (NOV) or a
Compliance Order to nine utilities covering 44 power plants, including the W. H.
Sammis  Plant.  In addition,  the U.S.  Department  of Justice filed eight civil
complaints against various investor-owned utilities,  which included a complaint
against OE and Penn in the U.S.  District  Court for the  Southern  District  of
Ohio.  The NOV and  complaint  allege  violations  of the Clean Air Act based on
operation  and  maintenance  of the W. H. Sammis Plant dating back to 1984.  The
complaint  requests  permanent  injunctive relief to require the installation of
"best available control technology" and civil penalties of up to $27,500 per day
of  violation.  On August 7, 2003,  the  United  States  District  Court for the
Southern District of Ohio ruled that 11 projects  undertaken at the W. H. Sammis
Plant  between 1984 and 1998 required  pre-construction  permits under the Clean
Air Act. The ruling  concludes the liability phase of the case, which deals with
applicability of Prevention of Significant Deterioration provisions of the Clean
Air Act. The remedy  phase,  which is currently  scheduled to be ready for trial
beginning July 19, 2004, will address civil penalties and what, if any,  actions
should be taken to further  reduce  emissions at the plant.  In the ruling,  the
Court  indicated  that the remedies it "may consider and impose  involved a much
broader, equitable analysis, requiring the Court to consider air quality, public
health,  economic  impact,  and  employment  consequences.  The  Court  may also
consider  the less  than  consistent  efforts  of the EPA to apply  and  further
enforce the Clean Air Act." The potential penalties that may be imposed, as well
as the  capital  expenditures  necessary  to comply  with  substantive  remedial
measures that may be required,  could have a material  adverse  impact on Penn's
financial  condition and results of operations.  Management is unable to predict
the  ultimate  outcome of this matter and no  liability  has been  accrued as of
March 31, 2004.

          Penn is complying with SO2 reduction  requirements under the Clean Air
Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity
from lower-emitting  plants,  and/or using emission  allowances.  NOx reductions
required by the 1990 Amendments are being achieved through  combustion  controls
and the generation of more electricity at  lower-emitting  plants.  In September
1998, the EPA finalized  regulations  requiring  additional NOx reductions  from
Penn's Ohio and  Pennsylvania  facilities.  The EPA's NOx Transport Rule imposes
uniform  reductions of NOx emissions  (an  approximate  85% reduction in utility
plant NOx emissions from projected 2007  emissions)  across a region of nineteen
states (including Michigan,  New Jersey, Ohio and Pennsylvania) and the District
of Columbia  based on a  conclusion  that such NOx  emissions  are  contributing
significantly to ozone levels in the eastern United States. State Implementation
Plans  (SIP) must  comply by May 31,  2004 with  individual  state NOx  budgets.
Pennsylvania  submitted a SIP that required  compliance  with the NOx budgets at
Penn's  Pennsylvania  facilities  by May 1,  2003.  Ohio  submitted  a SIP  that
requires  compliance  with the NOx budgets at Penn's Ohio  facilities by May 31,
2004.  Penn's  facilities  have  complied with the NOx budgets in 2003 and 2004,
respectively.

                                       98

<PAGE>

       Power Outage

          On August  14,  2003,  various  states  and parts of  southern  Canada
experienced a widespread power outage.  That outage affected  approximately  1.4
million  customers in  FirstEnergy's  service area.  On April 5, 2004,  the U.S.
-Canada Power System Outage Task Force released its final report on this outage.
The final report supercedes the interim report that had been issued in November,
2003. In the final report,  the Task Force concluded,  among other things,  that
the problems  leading to the outage began in  FirstEnergy's  Ohio service  area.
Specifically,   the  final  report  concludes,  among  other  things,  that  the
initiation of the August 14th power outage resulted from the coincidence on that
afternoon of several events,  including,  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 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 14th power outage and that it does not
adequately  address the  underlying  causes of the outage.  FirstEnergy  remains
convinced  that the outage  cannot be explained  by events on any one  utility's
system. The final report contains 46 "recommendations to prevent or minimize the
scope of future blackouts."  Forty-five of those recommendations relate to broad
industry  or policy  matters  while one  relates  to  activities  the Task Force
recommends be undertaken by FirstEnergy,  MISO,  PJM, and ECAR.  FirstEnergy has
undertaken  several  initiatives,  some prior to and some since the August  14th
power outage,  to enhance  reliability which are consistent with these and other
recommendations  and believes it will complete  those relating to summer 2004 by
June 30 (see  Reliability  Initiatives  below).  As  many of  these  initiatives
already were in process and budgeted in 2004,  FirstEnergy does not believe that
any  incremental  expenses  associated with  additional  initiatives  undertaken
during 2004 will have a material effect on its operations or financial  results.
FirstEnergy  notes,   however,  that  the  applicable  government  agencies  and
reliability   coordinators   may  take  a  different   view  as  to  recommended
enhancements or may recommend  additional  enhancements in the future that could
require additional, material expenditures.

       Reliability Initiatives

          On  October  15,  2003,  NERC  issued a Near  Term  Action  Plan  that
contained  recommendations  for all control areas and  reliability  coordinators
with  respect  to  enhancing  system   reliability.   Approximately  20  of  the
recommendations  were directed at the FirstEnergy  companies and broadly focused
on  initiatives  that are  recommended  for  completion  by summer  2004.  These
initiatives  principally  relate to  changes in voltage  criteria  and  reactive
resources  management;  operational  preparedness  and action  plans;  emergency
response   capabilities;   and,  preparedness  and  operating  center  training.
FirstEnergy   presented  a  detailed   compliance  plan  to  NERC,   which  NERC
subsequently  endorsed on May 7, 2004, and the various  initiatives are expected
to be completed no later than June 30, 2004.

          On February 26-27, 2004, certain FirstEnergy companies participated in
a NERC Control Area Readiness Audit. This audit, part of an announced program by
NERC to review  control area  operations  throughout  much of the United  States
during 2004, is an  independent  review to identify areas for  improvement.  The
final  audit  report was  completed  on April 30,  2004.  The report  identified
positive  observations  and included  various  recommendations  for improvement.
FirstEnergy  is currently  reviewing the audit results and  recommendations  and
expects to  implement  those  relating to summer  2004 by June 30.  Based on its
review thus far, FirstEnergy believes that none of the recommendations  identify
a  need  for  any  incremental  material  investment  or  upgrades  to  existing
equipment.  FirstEnergy notes, however, that NERC 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.

          On March 1, 2004, certain  FirstEnergy  companies filed, in accordance
with a November 25, 2003 order from the PUCO, their plan for addressing  certain
issues  identified  by the PUCO from the U.S. - Canada Power System  Outage Task
Force  interim  report.  In  particular,   the  filing  addressed   upgrades  to
FirstEnergy's  control room computer  hardware and software and  enhancements to
the  training of control  room  operators.  The PUCO will review the plan before
determining the next steps, if any, in the proceeding.

          On April 22,  2004,  FirstEnergy  filed  with FERC the  results of the
FERC-ordered independent study of part of Ohio's power grid. The study examined,
among other things,  the reliability of the transmission grid in critical points
in  the  Northern  Ohio  area  and  the  need,   if  any,  for  reactive   power
reinforcements  during summer 2004 and 2005.  FirstEnergy is currently reviewing
the  results  of that  study and  expects  to  complete  the  implementation  of
recommendations  relating to 2004 by this summer.  Based on its review thus far,
FirstEnergy  believes that the study does not recommend any incremental material
investment or 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.

                                       99

<PAGE>

          With respect to each of the  foregoing  initiatives,  FirstEnergy  has
requested and NERC has agreed to provide, a technical assistance team of experts
to provide ongoing guidance and assistance in implementing and confirming timely
and successful completion.

       Legal Matters

          Various  lawsuits,  claims and  proceedings  related to Penn's  normal
business  operations are pending against Penn, the most significant of which are
described above.

Critical Accounting Policies

          Penn  prepares  its  financial  statements  in  accordance  with GAAP.
Application  of these  principles  often  requires  a high  degree of  judgment,
estimates and assumptions  that affect financial  results.  All of Penn's assets
are subject to their own  specific  risks and  uncertainties  and are  regularly
reviewed  for  impairment.  Assets  related to the  application  of the policies
discussed  below are  similarly  reviewed  with  their  risks and  uncertainties
reflecting these specific factors.  Penn's more significant  accounting policies
are described below.

       Regulatory Accounting

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

       Revenue Recognition

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

       Pension and Other Postretirement Benefits Accounting

          FirstEnergy's  reported  costs of providing  non-contributory  defined
pension benefits and  postemployment  benefits other than pensions are dependent
upon  numerous  factors  resulting  from  actual  plan  experience  and  certain
assumptions.

          Pension  and  OPEB  costs  are   affected  by  employee   demographics
(including  age,  compensation  levels,  and employment  periods),  the level of
contributions  FirstEnergy makes to the plans, and earnings on plan assets. Such
factors may be further affected by business  combinations (such as FirstEnergy's
merger with GPU in November 2001),  which impacts  employee  demographics,  plan
experience  and other  factors.  Pension  and OPEB  costs are also  affected  by
changes  to key  assumptions,  including  anticipated  rates of  return  on plan
assets,  the discount rates and health care trend rates used in determining  the
projected benefit obligations for pension and OPEB costs.

          In accordance  with SFAS 87 and SFAS 106,  changes in pension and OPEB
obligations  associated with these factors may not be immediately  recognized as
costs on the income statement, but generally are recognized in future years over
the remaining average service period of plan participants.  SFAS 87 and SFAS 106
delay  recognition  of changes due to the  long-term  nature of pension and OPEB
obligations and the varying market  conditions likely to occur over long periods
of time. As such, significant portions of pension and OPEB costs recorded in any
period  may not  reflect  the actual  level of cash  benefits  provided  to plan
participants and are significantly influenced by assumptions about future market
conditions and plan participants' experience.

          In selecting an assumed discount rate, FirstEnergy considers currently
available rates of return on high-quality fixed income  investments  expected to
be   available   during  the  period  to  maturity  of  the  pension  and  other
postretirement  benefit  obligations.  Due to recent  declines in corporate bond
yields and interest rates in general,  FirstEnergy  reduced the assumed discount
rate as of December 31, 2003 to 6.25% from 6.75% used as of December 31, 2002.

                                      100

<PAGE>

          FirstEnergy's  assumed rate of return on pension plan assets considers
historical  market  returns and economic  forecasts for the types of investments
held by its pension trusts.  In 2003 and 2002, plan assets actually earned 24.0%
and (11.3)%,  respectively.  FirstEnergy's  pension  costs in 2003 and the first
quarter  of 2004 were  computed  assuming  a 9.0% rate of return on plan  assets
based upon  projections  of future  returns  and its  pension  trust  investment
allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash.

          Based on pension  assumptions  and pension  plan assets as of December
31, 2003,  FirstEnergy  will not be required to fund its pension  plans in 2004.
However,  health care cost trends have  significantly  increased and will affect
future  OPEB  costs.  The  2004  and  2003  composite  health  care  trend  rate
assumptions are approximately 10%-12% gradually decreasing to 5% in later years.
In determining  its trend rate  assumptions,  FirstEnergy  included the specific
provisions of its health care plans, the  demographics and utilization  rates of
plan participants,  actual cost increases  experienced in its health care plans,
and projections of future medical trend rates.

       Long-Lived Assets

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

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

       Nuclear Decommissioning

          In  accordance  with SFAS 143,  Penn  recognizes an ARO for the future
decommissioning  of its nuclear  power plants.  The ARO liability  represents an
estimate  of the fair  value of Penn's  current  obligation  related  to nuclear
decommissioning  and the  retirement of other assets.  A fair value  measurement
inherently  involves  uncertainty  in the amount and timing of settlement of the
liability.  Penn used an  expected  cash flow  approach  (as  discussed  in FASB
Concepts   Statement   No.  7)  to  measure   the  fair  value  of  the  nuclear
decommissioning  ARO. This approach applies probability  weighting to discounted
future  cash flow  scenarios  that  reflect a range of  possible  outcomes.  The
scenarios consider  settlement of the ARO at the expiration of the nuclear power
plants' current license and settlement based on an extended license term.

New Accounting Standards and Interpretations
--------------------------------------------

       FSP  106-1,  "Accounting  and  Disclosure  Requirements  Related  to  the
       Medicare Prescription Drug, Improvement and Modernization Act of 2003"

          Issued   January  12,  2004,   FSP  106-1   permits  a  sponsor  of  a
postretirement  health care plan that  provides a  prescription  drug benefit to
make a one-time  election to defer  accounting  for the effects of the  Medicare
Act.  Penn  elected to defer the effects of the  Medicare Act due to the lack of
specific guidance.  Pursuant to FSP 106-1, Penn began accounting for the effects
of the Medicare Act effective  January 1, 2004 as a result of a February 2, 2004
plan amendment that required remeasurement of the plan's obligations. See Note 2
for a discussion of the effect of the federal  subsidy and plan amendment on the
consolidated financial statements.

                                      101

<PAGE>

<TABLE>

                                        JERSEY CENTRAL POWER & LIGHT COMPANY

                                         CONSOLIDATED STATEMENTS OF INCOME
                                                    (Unaudited)

<CAPTION>
                                                                                          Three Months Ended
                                                                                                March 31,
                                                                                       -------------------------
                                                                                         2004             2003
                                                                                       ---------        --------
                                                                                                        Restated
                                                                                                      (See Note 2)

                                                                                             (In thousands)

<S>                                                                                   <C>              <C>
OPERATING REVENUES..............................................................      $ 498,124        $ 656,952
                                                                                      ---------        ---------


OPERATING EXPENSES AND TAXES:
   Fuel.........................................................................          1,213            1,334
   Purchased power..............................................................        259,592          362,667
   Other operating costs........................................................         85,603           69,088
                                                                                      ---------        ---------
       Total operation and maintenance expenses.................................        346,408          433,089
   Provision for depreciation and amortization..................................         94,701           96,973
   General taxes................................................................         15,932           15,812
   Income taxes.................................................................          9,113           35,735
                                                                                      ---------        ---------
       Total operating expenses and taxes.......................................        466,154          581,609
                                                                                      ---------        ---------


OPERATING INCOME................................................................         31,970           75,343


OTHER INCOME....................................................................          1,503            1,176
                                                                                      ---------        ---------


INCOME BEFORE NET INTEREST CHARGES..............................................         33,473           76,519
                                                                                      ---------        ---------


NET INTEREST CHARGES:
   Interest on long-term debt...................................................         20,728           23,312
   Allowance for borrowed funds used during construction........................           (120)            (123)
   Deferred interest............................................................           (923)          (3,202)
   Other interest expense (credit)..............................................            390             (159)
   Subsidiary's preferred stock dividend requirements...........................             --            2,674
                                                                                      ---------        ---------
       Net interest charges.....................................................         20,075           22,502
                                                                                      ---------        ---------


NET INCOME......................................................................         13,398           54,017


PREFERRED STOCK DIVIDEND REQUIREMENTS...........................................            125              125
                                                                                      ---------        ---------


EARNINGS ON COMMON STOCK........................................................      $  13,273        $  53,892
                                                                                      =========        =========


<FN>
The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company
are an integral part of these statements.
</FN>

                                                         102

</TABLE>

<PAGE>

<TABLE>
                                        JERSEY CENTRAL POWER & LIGHT COMPANY

                                            CONSOLIDATED BALANCE SHEETS
                                                    (Unaudited)

<CAPTION>
                                                                                       March 31,       December 31,
                                                                                          2004             2003
                                                                                      -----------------------------

                                                                                              (In thousands)
                                         ASSETS
UTILITY PLANT:
<S>                                                                                    <C>              <C>
   In service.....................................................................     $3,660,955       $3,642,467
   Less-Accumulated provision for depreciation....................................      1,383,599        1,367,042
                                                                                       ----------       ----------
                                                                                        2,277,356        2,275,425
   Construction work in progress..................................................         56,735           48,985
                                                                                       ----------       ----------
                                                                                        2,334,091        2,324,410
                                                                                       ----------       ----------
OTHER PROPERTY AND INVESTMENTS:
   Nuclear plant decommissioning trusts...........................................        130,623          125,945
   Nuclear fuel disposal trust....................................................        159,710          155,774
   Long-term notes receivable from associated companies...........................         20,635           19,579
   Other..........................................................................         18,085           18,744
                                                                                       ----------       ----------
                                                                                          329,053          320,042
                                                                                       ----------       ----------
CURRENT ASSETS:
   Cash and cash equivalents......................................................            282              271
   Receivables-
     Customers (less accumulated provisions of $3,924,000 and $4,296,000
       respectively, for uncollectible accounts)..................................        182,797          198,061
     Associated companies.........................................................         95,370           70,012
     Other (less accumulated provisions of $836,000 and $1,183,000
       respectively, for uncollectible accounts)..................................         34,879           46,411
   Materials and supplies, at average cost........................................          2,122            2,480
   Prepayments and other..........................................................         24,984           49,360
                                                                                       ----------       ----------
                                                                                          340,434          366,595
                                                                                       ----------       ----------
DEFERRED CHARGES:
   Regulatory assets..............................................................      2,456,605        2,558,214
   Goodwill.......................................................................      1,998,287        2,001,302
   Other..........................................................................          8,547            8,481
                                                                                       ----------       ----------
                                                                                        4,463,439        4,567,997
                                                                                       ----------       ----------
                                                                                       $7,467,017       $7,579,044
                                                                                       ==========       ==========

                           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       $  153,713
     Other paid-in capital........................................................      3,029,894        3,029,894
     Accumulated other comprehensive loss.........................................        (51,784)         (51,765)
     Retained earnings............................................................         30,406           22,132
                                                                                       ----------       ----------
         Total common stockholder's equity........................................      3,162,229        3,153,974
   Preferred stock not subject to mandatory redemption............................         12,649           12,649
   Long-term debt.................................................................      1,041,032        1,095,991
                                                                                       ----------       ----------
                                                                                        4,215,910        4,262,614
                                                                                        ---------       ----------
CURRENT LIABILITIES:
   Currently payable long-term debt...............................................        226,313          175,921
   Notes payable -
     Associated companies.........................................................        151,241          230,985
   Accounts payable-
     Associated companies.........................................................         42,066           42,410
     Other........................................................................         90,810          105,815
   Accrued  taxes.................................................................         50,400              919
   Accrued interest...............................................................         25,621           14,843
   Other..........................................................................         60,140           58,094
                                                                                       ----------       ----------
                                                                                          646,591          628,987
                                                                                       ----------       ----------
NONCURRENT LIABILITIES:
   Accumulated deferred income taxes..............................................        623,875          640,208
   Accumulated deferred investment tax credits....................................          7,315            7,711
   Power purchase contract loss liability ........................................      1,416,257        1,473,070
   Nuclear fuel disposal costs....................................................        168,314          167,936
   Asset retirement obligation....................................................        111,379          109,851
   Retirement benefits............................................................        147,505          159,219
   Other..........................................................................        129,871          129,448
                                                                                        ---------       ----------
                                                                                        2,604,516        2,687,443
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 3)................................     ----------       ----------
                                                                                       ----------       ----------
                                                                                       $7,467,017       $7,579,044
                                                                                       ==========       ==========
<FN>
The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company
are an integral part of these balance sheets.
</FN>

                                                         103

</TABLE>

<PAGE>

<TABLE>

                                        JERSEY CENTRAL POWER & LIGHT COMPANY

                                       CONSOLIDATED STATEMENTS OF CASH FLOWS
                                                    (Unaudited)

<CAPTION>
                                                                                        Three Months Ended
                                                                                              March 31,
                                                                                    ---------------------------
                                                                                      2004               2003
                                                                                    ---------          --------
                                                                                                       Restated
                                                                                                     (See Note 2)
                                                                                           (In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
<S>                                                                                <C>                <C>
Net income...................................................................      $  13,398          $  54,017
   Adjustments to reconcile net income to net
     cash from operating activities-
       Provision for depreciation and amortization...........................         94,701             96,973
       Other amortization....................................................             24                185
       Deferred costs, net...................................................        (49,122)           (71,888)
       Deferred income taxes, net............................................            627             14,977
       Investment tax credits, net...........................................           (397)              (575)
       Receivables...........................................................          1,438             19,788
       Materials and supplies................................................            358               (226)
       Accounts payable......................................................        (15,349)           (90,178)
       Prepayments and other current assets..................................         24,376             16,044
       Accrued taxes.........................................................         49,480             45,157
       Accrued interest......................................................         10,778              5,771
       Accrued retirement benefit obligation.................................        (11,714)                --
       Other.................................................................          3,444              6,034
                                                                                   ---------          ---------
         Net cash provided from operating activities.........................        122,042             96,079
                                                                                   ---------          ---------

CASH FLOWS FROM FINANCING ACTIVITIES:
   Redemptions and Repayments -
     Long-term debt..........................................................         (3,591)           (10,090)
     Short-term borrowings, net..............................................        (79,744)                --
   Dividend Payments-
     Common stock............................................................         (5,000)           (89,000)
     Preferred stock.........................................................           (125)              (125)
                                                                                   ---------          ---------
         Net cash used for financing activities..............................        (88,460)           (99,215)
                                                                                   ---------          ---------

CASH FLOWS FROM INVESTING ACTIVITIES:
   Property additions........................................................        (28,212)           (24,551)
   Loans from (to) associated companies, net.................................         (1,056)            24,750
   Other.....................................................................         (4,303)               (50)
                                                                                   ---------          ---------
         Net cash provided from (used for) investing activities..............        (33,571)               149
                                                                                   ---------          ---------

Net increase (decrease) in cash and cash equivalents.........................             11             (2,987)
Cash and cash equivalents at beginning of period ............................            271              4,823
                                                                                   ---------          ---------
Cash and cash equivalents at end of period...................................      $     282          $   1,836
                                                                                   =========          =========


<FN>
The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company
are an integral part of these statements.
</FN>

                                                         104

</TABLE>

<PAGE>


                        REPORT OF INDEPENDENT ACCOUNTANTS


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, 2004, and the related
consolidated  statements  of income and cash  flows for each of the  three-month
periods ended March 31, 2004 and 2003.  These interim  financial  statements are
the responsibility of the Company's management.

We conducted our review in accordance with standards established by the American
Institute  of  Certified  Public  Accountants.  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 generally
accepted  auditing  standards,  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.

As discussed in Note 2 to the consolidated  interim  financial  statements,  the
Company has  restated  its  previously  issued  consolidated  interim  financial
statements for the three-month period ended March 31, 2003.

We previously audited in accordance with auditing  standards  generally accepted
in the  United  States  of  America,  the  consolidated  balance  sheet  and the
consolidated  statement  of  capitalization  as of December  31,  2003,  and the
related  consolidated   statements  of  income,   common  stockholder's  equity,
preferred  stock,  cash flows and taxes for the year then  ended (not  presented
herein),  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 1(E) to those consolidated financial statements) dated
February 25, 2004,  we expressed an  unqualified  opinion on those  consolidated
financial  statements.  In  our  opinion,  the  information  set  forth  in  the
accompanying  condensed  consolidated  balance sheet as of December 31, 2003, 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 7, 2004

                                      105

<PAGE>


                      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 provides  regulated  transmission and  distribution  services in northern,
western and east  central New Jersey.  New Jersey  customers  are able to choose
their electricity  suppliers as a result of legislation  which  restructured the
electric utility industry. JCP&L's regulatory plan required unbundling the price
for   electricity   into  its   component   elements  -  including   generation,
transmission,  distribution  and transition  charges.  Also under the regulatory
plan,  JCP&L  continues  to deliver  power to homes and  businesses  through its
existing  distribution  system and is required to  maintain  the PLR  obligation
known as BGS for customers who elect to retain JCP&L as their power supplier.

Restatements of Previously Reported Quarterly Results
-----------------------------------------------------

          As discussed in Note 2 to Consolidated  Financial Statements,  JCP&L's
quarterly  results for the first  quarter of 2003 have been  restated to correct
the amounts reported for operating expenses. JCP&L's costs which were originally
recorded as operating  expenses and should have been capitalized to construction
were $0.2 million  ($0.1 million  after-tax)  in the first quarter of 2003.  The
impact of these  adjustments  was not material to JCP&L's  Consolidated  Balance
Sheets or Consolidated Statements of Cash Flows for any quarter of 2003.

Results of Operation
--------------------

          Earnings on common stock in the first quarter of 2004 decreased to $13
million from $54 million in the first quarter of 2003. Lower operating  revenues
primarily due to decreases in wholesale  sales and lower rates  resulting from a
NJBPU rate  order and higher  operating  costs  were  partially  offset by lower
purchased power costs.

          Operating  revenues  decreased  by $159  million or 24.2% in the first
quarter  of 2004  compared  with the same  period in 2003.  The  lower  revenues
resulted from lower  wholesale  revenues that  decreased by $78 million over the
first quarter of 2003.  JCP&L entered into long-term  power purchase  agreements
with the  divestiture of its generating  facilities.  JCP&L was able to sell any
power in  excess of its  retail  customer  needs to the  wholesale  market.  The
long-term power purchase agreements ended during 2003 and as a result,  sales to
the wholesale market also ceased.

          While distribution  deliveries  increased 1.3% in the first quarter of
2004  from  the  corresponding   quarter  of  2003,  revenues  from  electricity
throughput  declined by $76 million.  On July 25, 2003, the NJBPU  announced its
JCP&L base electric rate  proceeding  decision (see Regulatory  Matters),  which
reduced JCP&L's  distribution  rates  effective  August 1, 2003. The lower rates
reduced  revenues by $33 million in the first quarter of 2004. A higher level of
shopping contributed to the remainder of the decline in operating revenues.  The
industrial  customer sector  deliveries  increased 6.1% primarily due to JCP&L's
largest  industrial  customer  increasing  its  consumption  by 18%.  Changes in
distribution  deliveries  in the first  quarter of 2004  compared with the first
quarter of 2003 are summarized in the following table:


           Changes in Kilowatt-Hour Deliveries
           ----------------------------------------------------------
           Increase (Decrease)
                      Residential...........................     1.2%
                      Commercial............................    (0.1)%
                      Industrial............................     6.1%
           ----------------------------------------------------------
           Total Distribution Deliveries....................     1.3%
           ==========================================================

Operating Expenses and Taxes

          Total operating expenses and taxes decreased $115 million in the first
quarter  of 2004  compared  with the first  quarter  of 2003,  primarily  due to
reduced  purchased  power  costs  offset in part by  increased  other  operating
expenses.  The following  table presents  changes from the prior year by expense
category.

                                      106

<PAGE>

          Operating Expenses and Taxes - Changes
          -----------------------------------------------------------------
           Increase (Decrease)                                 (In millions)
          Fuel.............................................      $  --
          Purchased power..................................       (103)
          Other operating costs............................         17
          ------------------------------------------------------------
            Total operation and maintenance expenses.......        (86)

          Provision for depreciation and amortization......         (2)
          General taxes....................................         --
          Income taxes.....................................        (27)
          -------------------------------------------------------------
            Total operating expenses and taxes.............      $(115)
          =============================================================

          Lower purchased power costs in the first quarter of 2004,  compared to
the  same  quarter  of 2003,  were  due  primarily  to  decreased  kilowatt-hour
purchases  through two-party  agreements.  The increase in other operating costs
was  attributed  to JCP&L's  accelerated  reliability  program  (see  Regulatory
Matters).

       Net Interest Charges

          Net interest  charges  decreased by $2 million in the first quarter of
2004 compared with the first quarter of 2003,  primarily due to debt redemptions
since the end of the first quarter of 2003.

Capital Resources and Liquidity
-------------------------------

          JCP&L's cash requirements in 2004 for operating expenses, construction
expenditures  and  scheduled  debt  maturities  are  expected  to be met without
increasing its net debt and preferred  stock  outstanding.  Available  borrowing
capacity under  short-term  credit  facilities  with  affiliates will be used to
manage working capital  requirements.  Over the next two years, JCP&L expects to
meet its contractual  obligations with cash from operations.  Thereafter,  JCP&L
expects to use a combination of cash from  operations and funds from the capital
markets.

       Changes in Cash Position

          JCP&L had $0.3  million of cash and cash  equivalents  as of March 31,
2004 and December 31, 2003.

       Cash Flows From Operating Activities

          Cash provided from  operating  activities  during the first quarter of
2004, compared to the first quarter of 2003 were as follows:

          Operating Cash Flows                     2004          2003
          -------------------------------------------------------------
                                                      (In millions)

          Cash earnings (1)....................   $ 59            $94
          Working capital and other............     63              2
          -------------------------------------------------------------

          Total................................   $122            $96
          =============================================================

          (1) Includes net income, depreciation and amortization, deferred
              costs  recoverable  as regulatory  assets,  deferred  income
              taxes and investment tax credits.

          Net cash from  operating  activities  increased to $122 million in the
first  quarter  of 2004 from $96  million  in the  first  quarter  of 2003.  The
increase  was due to a $61  million  increase  in funds  provided  from  working
capital and other changes,  partially  offset by a $35 million  decrease in cash
earnings.  The increase in working  capital  reflects a $75 million  decrease in
cash  requirements  for accounts  payable in 2004 as compared to 2003.  The cash
earnings decrease was mostly attributable to lower revenues.

       Cash Flows From Financing Activities

          In the first quarter of 2004,  net cash used for financing  activities
of $88 million  primarily  reflected the redemption of $80 million of short-term
borrowings, $3 million of long-term debt and $5 million of common stock dividend
payments  to  FirstEnergy.  In the  first  quarter  of 2003,  net cash  used for
financing  activities  totaled $99 million,  primarily due to the  redemption of
debt and $89 million in common stock dividend payments to FirstEnergy.

          JCP&L may borrow from its affiliates on a short-term basis. JCP&L will
not issue first mortgage bonds other than as collateral for senior notes,  since
its senior note  indenture  prohibits  (subject to certain  exceptions)  it from

                                      107

<PAGE>

issuing  any debt which is senior to the  senior  notes.  Based upon  applicable
earnings  coverage  tests,  JCP&L  could not issue any first  mortgage  bonds or
preferred stock as of March 31, 2004.

          On April 23, 2004,  JCP&L  issued $300 million of 5.625%  Senior Notes
due 2016. The proceeds of this transaction will be used to redeem $40 million of
7.98% JCP&L  Series C MTNs due 2023 and $50 million of 6.78% JCP&L Series C MTNs
due 2005. The remaining  proceeds will be used to fund the mandatory  redemption
of  JCP&L's  $160  million  of  7.125%  FMB due  October  1,  2004 and to reduce
short-term debt.

          JCP&L 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 2004 was 1.30%.

          On February 6, 2004, Moody's  downgraded  FirstEnergy senior unsecured
debt to Baa3 from Baa2 and downgraded  the senior secured debt of JCP&L,  Met-Ed
and Penelec to Baa1 from A2. Moody's also  downgraded the preferred stock rating
of JCP&L to Ba1 from Baa2 and the  senior  unsecured  rating of  Penelec to Baa2
from A2. The ratings of OE, CEI, TE and Penn were  confirmed.  Moody's said that
the  lower  ratings  were  prompted  by:  "1) high  consolidated  leverage  with
significant  holding company debt, 2) a degree of regulatory  uncertainty in the
service  territories in which the company  operates,  3) risks  associated  with
investigations of the causes of the August 2003 blackout, and related securities
litigation,  and 4) a  narrowing  of  the  ratings  range  for  the  FirstEnergy
operating utilities,  given the degree to which FirstEnergy increasingly manages
the utilities as a single system and the significant financial interrelationship
among the subsidiaries."

          On March 9, 2004, S&P stated that the NRC's permission for FirstEnergy
to restart the Davis-Besse nuclear plant was positive for credit quality because
it would positively affect cash flow by eliminating  replacement power costs and
"demonstrating   management's  ability  to  overcome  operational   challenges."
However, S&P did not change  FirstEnergy's  ratings or outlook because it stated
that financial performance still "significantly lags expectations and management
faces other operational hurdles."

       Cash Flows From Investing Activities

          Net cash used for  investing  activities  totaled  $34  million in the
first quarter of 2004, compared with net cash provided from investing activities
of $0.1  million in the first  quarter of 2003.  The $34  million  increase  was
primarily due to the $1 million in loan payments made to associated companies in
2004 as compared to the $25 million in loan payments  received  from  associated
companies  in 2003,  as well as $4 million in  increased  property  additions in
2004.

          During the last  three  quarters  of 2004,  capital  requirements  for
property  additions are expected to be about $122 million.  JCP&L has additional
requirements of  approximately  $160 million for maturing  long-term debt during
the remainder of 2004. These cash requirements (excluding debt refinancings) are
expected to be satisfied from internal cash and short-term credit arrangements.

Market Risk Information
-----------------------

          JCP&L  uses  various  market  risk  sensitive  instruments,  including
derivative  contracts,  primarily  to  manage  the risk of  price  fluctuations.
FirstEnergy's Risk Policy Committee,  comprised of executive officers, exercises
an independent risk oversight  function to ensure compliance with corporate risk
management policies and prudent 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 future contracts.  The derivatives are
used for  hedging  purposes.  Most of  JCP&L'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 2004 is  summarized  in the
following table:

                                      108

<PAGE>

<TABLE>

Increase (Decrease) in the Fair Value
of Commodity Derivative Contracts
<CAPTION>
                                                                Non-Hedge     Hedge      Total
-------------------------------------------------------------------------------------------------
                                                                           (In millions)
Change in the Fair Value of Commodity Derivative Contracts
<S>                                 <C>                            <C>       <C>         <C>
Outstanding net asset as of January 1, 2004...................     $ 16      $  --       $ 16
New contract value when entered...............................       --         --         --
Additions/change in value of existing contracts...............       (1)        --         (1)
Change in techniques/assumptions..............................       --         --         --
Settled contracts.............................................       --         --         --
-------------------------------------------------------------------------------------------------
Net Assets - Derivatives Contracts as of March 31, 2004 (1)...     $ 15      $  --       $ 15
=================================================================================================

Impact of Changes in Commodity Derivative Contracts (2)
Income Statement Effects (Pre-Tax)............................     $ --      $  --       $ --
Balance Sheet Effects:
Other Comprehensive Income (Pre-Tax)..........................     $ --      $  --       $ --
Regulatory Liability..........................................     $ (1)     $  --       $ (1)
</TABLE>

(1) Includes $15 million in non-hedge commodity derivative contracts which
    are offset by a regulatory  liability.  (2) Represents the increase in
    value  of  existing  contracts,   settled  contracts  and  changes  in
    techniques/assumptions.

Derivatives included on the Consolidated Balance Sheet as of March 31, 2004:

                                                    Non-Hedge    Hedge    Total
          ---------------------------------------------------------------------
                                                             (In millions)
          Current-
                Other Assets......................    $--      $  --      $--

          Non-Current-
                Other Deferred Charges............     15         --       15
          -------------------------------------------------------------------

                Net assets........................    $15      $  --      $15
          ===================================================================

          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, JCP&L relies 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.  Sources  of  information  for  the  valuation  of
derivative contracts by year are summarized in the following table:

<TABLE>
<CAPTION>
Source of Information
- Fair Value by Contract Year             2004       2005       2006       2007       Thereafter         Total
--------------------------------------------------------------------------------------------------------------
                                                                 (In millions)
<S>                                       <C>        <C>      <C>        <C>            <C>          <C>
Prices based on external sources(1)       $ 2        $ 3      $ --       $ --           $ --         $  5
Prices based on models                    --         --          2          2              6           10
--------------------------------------------------------------------------------------------------------------

    Total(2)                              $ 2        $ 3       $ 2        $ 2            $ 6          $15
===============================================================================================================
</TABLE>

(1) Broker quote sheets.
(2) Includes $15 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  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, 2004.

       Equity Price Risk

          Included in JCP&L's  nuclear  decommissioning  trust  investments  are
marketable equity securities  carried at their market value of approximately $72
million  and  $69  million  as  of  March  31,  2004  and   December  31,  2003,
respectively.  A hypothetical  10% decrease in prices quoted by stock  exchanges
would result in a $7 million reduction in fair value as of March 31, 2004.


                                   109

<PAGE>

Outlook
-------

          Beginning  in 1999,  all of  JCP&L's  customers  were  able to  select
alternative  energy  suppliers.  JCP&L  continues to deliver  power to homes and
businesses through its existing distribution system, which remains regulated. To
support customer choice,  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.  All of JCP&L's
regulatory  assets are expected to continue to be recovered under the provisions
of the regulatory proceedings discussed below. JCP&L's regulatory assets totaled
$2.5  billion  and $2.6  billion as of March 31,  2004 and  December  31,  2003,
respectively.

       Regulatory Matters

          Under New Jersey  transition  legislation,  all electric  distribution
companies  were  required to file rate cases to determine the level of unbundled
rate components to become effective August 1, 2003. JCP&L's two August 2002 rate
filings requested  increases in base electric rates of approximately $98 million
annually  and  requested  the recovery of deferred  energy  costs that  exceeded
amounts being recovered under the current MTC and SBC rates; one proposed method
of recovery of these costs is the  securitization of the deferred balance.  This
securitization  methodology  is similar to the Oyster Creek  securitization.  In
July 2003, the NJBPU announced its JCP&L base electric rate proceeding  decision
which reduced JCP&L's annual  revenues by  approximately  $62 million  effective
August 1, 2003. The NJBPU decision also provided for an interim return on equity
of 9.5% on  JCP&L's  rate base for the next six to twelve  months.  During  that
period, JCP&L will initiate another proceeding to request recovery of additional
costs  incurred to enhance system  reliability.  In that  proceeding,  the NJBPU
could increase the 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. The revenue decrease in the decision  consists of
a $223  million  decrease in the  electricity  delivery  charge,  a $111 million
increase  due to the  August  1, 2003  expiration  of  annual  customer  credits
previously  mandated  by the New Jersey  transition  legislation,  a $49 million
increase in the MTC tariff  component,  and a net $1 million increase in the SBC
charge.  The MTC allowed for the  recovery  of $465  million in deferred  energy
costs over the next ten years on an interim basis, thus disallowing $153 million
of the $618 million provided for in a preliminary  settlement  agreement between
certain parties. As a result,  JCP&L recorded charges to net income for the year
ended  December 31, 2003,  aggregating  $185 million  ($109  million net of tax)
consisting  of the $153  million  deferred  energy  costs and  other  regulatory
assets. JCP&L filed a motion for rehearing and reconsideration with the NJBPU on
August 15, 2003 with respect to the following  issues:  (1) the  disallowance of
the $153  million  deferred  energy  costs;  (2) the  reduced  rate of return on
equity; and (3) $42.7 million of disallowed costs to achieve merger savings.  On
October 10,  2003,  the NJBPU held the motion in abeyance  until the final NJBPU
decision and order is issued. This is expected to occur in the second quarter of
2004.

          On July  5,  2003,  JCP&L  experienced  a  series  of  34.5  kilo-volt
sub-transmission  line faults that  resulted in outages on the New Jersey shore.
The NJBPU  instituted an investigation  into these outages,  and directed that a
Special Reliability Master be hired to oversee the investigation. On December 8,
2003, the Special Reliability Master issued his Interim Report recommending that
JCP&L implement a series of actions to improve  reliability in the area affected
by the  outages.  The NJBPU  adopted the  findings  and  recommendations  of the
Interim  Report on  December  17,  2003,  and  ordered  JCP&L to  implement  the
recommended  actions on a staggered basis,  with initial actions to be completed
by March 31,  2004.  JCP&L  expects to spend $12.5  million  implementing  these
actions during 2004. In late 2003, in accordance  with a Stipulation  concerning
an August 2002 storm outage,  the NJBPU engaged Booth & Associates to conduct an
audit of the  planning,  operations  and  maintenance  practices,  policies  and
procedures of JCP&L.  The audit was expanded to include the July 2003 outage and
was completed in January 2004. JCP&L is awaiting the issuance of the final audit
report and is unable to predict the outcome of the audit;  no liability has been
accrued as of March 31, 2004.

          On April 28, 2004,  the NJBPU  directed JCP&L to file testimony by the
end of May 2004,  either  supporting  a  continuation  of the current  level and
duration of the funding of TMI-2 decommissioning costs by New Jersey ratepayers,
or, alternatively, proposing a reduction, termination or capping of the funding.
JCP&L cannot predict the outcome of this matter.

       Environmental Matters

          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 be held  liable  on a joint and  several  basis.  Therefore,  environmental
liabilities   that  are  considered   probable  have  been   recognized  on  the
Consolidated  Balance Sheets,  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. JCP&L has
accrued  liabilities  aggregating  approximately  $45.6  million as of March 31,
2004. JCP&L accrues environmental  liabilities only when it can conclude that it
is  probable  that an  obligation  for  such  costs  exists  and can  reasonably
determine the amount of such costs.  Unasserted  claims are reflected in JCP&L's
determination  of  environmental  liabilities and are accrued in the period that
they are both probable and reasonably estimable.

                                      110

<PAGE>

       Power Outage

          On August  14,  2003,  various  states  and parts of  southern  Canada
experienced a widespread power outage.  That outage affected  approximately  1.4
million  customers in  FirstEnergy's  service area.  On April 5, 2004,  the U.S.
-Canada Power System Outage Task Force released its final report on this outage.
The final report supercedes the interim report that had been issued in November,
2003. In the final report,  the Task Force concluded,  among other things,  that
the problems  leading to the outage began in  FirstEnergy's  Ohio service  area.
Specifically,   the  final  report  concludes,  among  other  things,  that  the
initiation of the August 14th power outage resulted from the coincidence on that
afternoon of several events,  including,  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 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 14th power outage and that it does not
adequately  address the  underlying  causes of the outage.  FirstEnergy  remains
convinced  that the outage  cannot be explained  by events on any one  utility's
system. The final report contains 46 "recommendations to prevent or minimize the
scope of future blackouts."  Forty-five of those recommendations relate to broad
industry  or policy  matters  while one  relates  to  activities  the Task Force
recommends be undertaken by FirstEnergy,  MISO,  PJM, and ECAR.  FirstEnergy has
undertaken  several  initiatives,  some prior to and some since the August  14th
power outage,  to enhance  reliability which are consistent with these and other
recommendations  and believes it will complete  those relating to summer 2004 by
June 30 (see  Reliability  Initiatives  below).  As  many of  these  initiatives
already were in process and budgeted in 2004,  FirstEnergy does not believe that
any  incremental  expenses  associated with  additional  initiatives  undertaken
during 2004 will have a material effect on its operations or financial  results.
FirstEnergy  notes,   however,  that  the  applicable  government  agencies  and
reliability   coordinators   may  take  a  different   view  as  to  recommended
enhancements or may recommend  additional  enhancements in the future that could
require additional, material expenditures.

       Reliability Initiatives

          On  October  15,  2003,  NERC  issued a Near  Term  Action  Plan  that
contained  recommendations  for all control areas and  reliability  coordinators
with  respect  to  enhancing  system   reliability.   Approximately  20  of  the
recommendations  were directed at the FirstEnergy  companies and broadly focused
on  initiatives  that are  recommended  for  completion  by summer  2004.  These
initiatives  principally  relate to  changes in voltage  criteria  and  reactive
resources  management;  operational  preparedness  and action  plans;  emergency
response   capabilities;   and,  preparedness  and  operating  center  training.
FirstEnergy   presented  a  detailed   compliance  plan  to  NERC,   which  NERC
subsequently  endorsed on May 7, 2004, and the various  initiatives are expected
to be completed no later than June 30, 2004.

          On February 26-27, 2004, certain FirstEnergy companies participated in
a NERC Control Area Readiness Audit. This audit, part of an announced program by
NERC to review  control area  operations  throughout  much of the United  States
during 2004, is an  independent  review to identify areas for  improvement.  The
final  audit  report was  completed  on April 30,  2004.  The report  identified
positive  observations  and included  various  recommendations  for improvement.
FirstEnergy  is currently  reviewing the audit results and  recommendations  and
expects to  implement  those  relating to summer  2004 by June 30.  Based on its
review thus far, FirstEnergy believes that none of the recommendations  identify
a  need  for  any  incremental  material  investment  or  upgrades  to  existing
equipment.  FirstEnergy notes, however, that NERC 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.

          On March 1, 2004, certain  FirstEnergy  companies filed, in accordance
with a November 25, 2003 order from the PUCO, their plan for addressing  certain
issues  identified  by the PUCO from the U.S. - Canada Power System  Outage Task
Force  interim  report.  In  particular,   the  filing  addressed   upgrades  to
FirstEnergy's  control room computer  hardware and software and  enhancements to
the  training of control  room  operators.  The PUCO will review the plan before
determining the next steps, if any, in the proceeding.

          On April 22,  2004,  FirstEnergy  filed  with FERC the  results of the
FERC-ordered independent study of part of Ohio's power grid. The study examined,
among other things,  the reliability of the transmission grid in critical points
in  the  Northern  Ohio  area  and  the  need,   if  any,  for  reactive   power
reinforcements  during summer 2004 and 2005.  FirstEnergy is currently reviewing
the  results  of that  study and  expects  to  complete  the  implementation  of
recommendations  relating to 2004 by this summer.  Based on its review thus far,
FirstEnergy  believes that the study does not recommend any incremental material
investment or 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.

                                      111

<PAGE>

          With respect to each of the  foregoing  initiatives,  FirstEnergy  has
requested and NERC has agreed to provide, a technical assistance team of experts
to provide ongoing guidance and assistance in implementing and confirming timely
and successful completion.

       Legal Matters

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

          In July 1999, the Mid-Atlantic  states experienced a severe heat storm
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 New Jersey  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.

          Since July 1999, this litigation has involved a substantial  amount of
legal discovery including interrogatories,  request for production of documents,
preservation and inspection of evidence, and depositions of the named plaintiffs
and many JCP&L  employees.  In addition,  there have been many motions filed and
argued by the parties  involving  issues such as the  primary  jurisdiction  and
findings of the NJBPU, consumer fraud by JCP&L, strict product liability,  class
decertification, and the damages claimed by the plaintiffs. In January 2000, the
NJ Appellate  Division  determined that the trial court has proper  jurisdiction
over this  litigation.  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 products 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 have been appealed to the Appellation  Division and oral argument
is scheduled for May 2004. FirstEnergy is unable to predict the outcome of these
matters and no liability has been accrued as of March 31, 2004.

Critical Accounting Policies

          JCP&L  prepares its  consolidated  financial  statements in accordance
with GAAP.  Application  of these  principles  often  requires a high  degree of
judgment,  estimates  and  assumptions  that affect  financial  results.  All of
JCP&L's assets are subject to their own specific risks and uncertainties and are
regularly  reviewed for  impairment.  Assets  related to the  application of the
policies   discussed   below  are  similarly   reviewed  with  their  risks  and
uncertainties  reflecting  these  specific  factors.  JCP&L's  more  significant
accounting policies are described below.

       Regulatory Accounting

          JCP&L is subject  to  regulation  that sets the  prices  (rates) it is
permitted to charge its customers  based on costs that the  regulatory  agencies
determine JCP&L is permitted to recover. At times,  regulators permit the future
recovery through rates of costs that would be currently charged to expense by an
unregulated  company.  This  rate-making  process  results in the  recording  of
regulatory assets based on anticipated  future cash inflows.  As a result of the
changing regulatory  framework in New Jersey, a significant amount of regulatory
assets have been recorded - $2.5 billion as of March 31, 2004.  JCP&L  regularly
reviews these assets to assess their ultimate recoverability within the approved
regulatory  guidelines.  Impairment risk associated with these assets relates to
potentially adverse legislative, judicial or regulatory actions in the future.

       Derivative Accounting

          Determination  of appropriate  accounting for derivative  transactions
requires the involvement of management representing operations, finance and risk
assessment.  In order to determine the  appropriate  accounting  for  derivative
transactions,  the  provisions of the contract need to be carefully  assessed in
accordance  with  the  authoritative   accounting  literature  and  management's
intended use of the derivative.  New authoritative  guidance  continues to shape
the  application  of  derivative  accounting.   Management's   expectations  and
intentions  are key factors in  determining  the  appropriate  accounting  for a
derivative  transaction and, as a result,  such  expectations and intentions are
documented. Derivative contracts that are determined to fall within the scope of
SFAS 133, as amended, must be recorded at their fair value. Active market prices
are not always  available  to  determine  the fair value of the later years of a
contract,  requiring  that various  assumptions  and  estimates be used in their
valuation.  JCP&L continually  monitors its derivative contracts to determine if
its  activities,  expectations,  intentions,  assumptions  and estimates  remain
valid. As part of its normal operations,  JCP&L enters into commodity contracts,
as well as  interest  rate  swaps,  which  increase  the  impact  of  derivative
accounting judgments.

                                      112

<PAGE>

       Revenue Recognition

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

       Pension and Other Postretirement Benefits Accounting

          FirstEnergy's  reported  costs of providing  non-contributory  defined
pension benefits and  postemployment  benefits other than pensions are dependent
upon  numerous  factors  resulting  from  actual  plan  experience  and  certain
assumptions.

          Pension  and  OPEB  costs  are   affected  by  employee   demographics
(including  age,  compensation  levels,  and employment  periods),  the level of
contributions  FirstEnergy makes to the plans, and earnings on plan assets. Such
factors may be further affected by business  combinations (such as FirstEnergy's
merger with GPU in November 2001),  which impacts  employee  demographics,  plan
experience  and other  factors.  Pension  and OPEB  costs are also  affected  by
changes  to key  assumptions,  including  anticipated  rates of  return  on plan
assets,  the discount rates and health care trend rates used in determining  the
projected benefit obligations for pension and OPEB costs.

          In accordance  with SFAS 87 and SFAS 106,  changes in pension and OPEB
obligations  associated with these factors may not be immediately  recognized as
costs on the income statement, but generally are recognized in future years over
the remaining average service period of plan participants.  SFAS 87 and SFAS 106
delay  recognition  of changes due to the  long-term  nature of pension and OPEB
obligations and the varying market  conditions likely to occur over long periods
of time. As such, significant portions of pension and OPEB costs recorded in any
period  may not  reflect  the actual  level of cash  benefits  provided  to plan
participants and are significantly influenced by assumptions about future market
conditions and plan participants' experience.

          In selecting an assumed discount rate, FirstEnergy considers currently
available rates of return on high-quality fixed income  investments  expected to
be   available   during  the  period  to  maturity  of  the  pension  and  other
postretirement  benefit  obligations.  Due to recent  declines in corporate bond
yields and interest rates in general,  FirstEnergy  reduced the assumed discount
rate as of December 31, 2003 to 6.25% from 6.75% used as of December 31, 2002.

          FirstEnergy's  assumed rate of return on pension plan assets considers
historical  market  returns and economic  forecasts for the types of investments
held by its pension trusts.  In 2003 and 2002, plan assets actually earned 24.0%
and (11.3)%,  respectively.  FirstEnergy's  pension  costs in 2003 and the first
quarter  of 2004 were  computed  assuming  a 9.0% rate of return on plan  assets
based upon  projections  of future  returns  and its  pension  trust  investment
allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash.

          Based on pension  assumptions  and pension  plan assets as of December
31, 2003,  FirstEnergy  will not be required to fund its pension  plans in 2004.
However,  health care cost trends have  significantly  increased and will affect
future  OPEB  costs.  The  2004  and  2003  composite  health  care  trend  rate
assumptions are approximately 10%-12% gradually decreasing to 5% in later years.
In determining  its trend rate  assumptions,  FirstEnergy  included the specific
provisions of its health care plans, the  demographics and utilization  rates of
plan participants,  actual cost increases  experienced in its health care plans,
and projections of future medical trend rates.

       Long-Lived Assets

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

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

                                      113

<PAGE>

       Nuclear Decommissioning

          In accordance  with SFAS 143,  JCP&L  recognizes an ARO for the future
decommissioning  of TMI-2. The ARO liability  represents an estimate of the fair
value of JCP&L's current obligation related to nuclear  decommissioning.  A fair
value measurement  inherently  involves  uncertainty in the amount and timing of
settlement  of the  liability.  JCP&L used an expected  cash flow  approach  (as
discussed  in FASB  Concepts  Statement  No. 7) to measure the fair value of the
nuclear  decommissioning  ARO. This approach  applies  probability  weighting to
discounted future cash flow scenarios that reflect a range of possible outcomes.

       Goodwill

          In a business  combination,  the excess of the purchase price over the
estimated  fair  values  of the  assets  acquired  and  liabilities  assumed  is
recognized  as  goodwill.  Based on the  guidance  provided  by SFAS 142,  JCP&L
evaluates  goodwill  for  impairment  at least  annually  and would make such an
evaluation  more  frequently  if  indicators  of  impairment  should  arise.  In
accordance with the accounting  standard,  if the fair value of a reporting unit
is less than its carrying value (including goodwill), the goodwill is tested for
impairment.  If impairment were to be indicated,  JCP&L would recognize a loss -
calculated as the difference  between the implied fair value of its goodwill and
the carrying  value of the goodwill.  JCP&L's annual review was completed in the
third quarter of 2003,  with no  impairment  indicated.  The  forecasts  used in
JCP&L's  evaluations of goodwill reflect operations  consistent with its general
business  assumptions.  Unanticipated  changes in those assumptions could have a
significant  effect on JCP&L's  future  evaluations  of  goodwill.  In the first
quarter of 2004, JCP&L reduced goodwill by $3 million for interest received on a
pre-merger  income tax  refund.  As of March 31,  2004,  JCP&L had $2 billion of
goodwill.

New Accounting Standards and Interpretations

       FSP  106-1,  "Accounting  and  Disclosure  Requirements  Related  to  the
       Medicare Prescription Drug, Improvement and Modernization Act of 2003"

          Issued   January  12,  2004,   FSP  106-1   permits  a  sponsor  of  a
postretirement  health care plan that  provides a  prescription  drug benefit to
make a one-time  election to defer  accounting  for the effects of the  Medicare
Act.  FirstEnergy  elected to defer the effects of the  Medicare  Act due to the
lack of specific guidance.  Pursuant to FSP 106-1,  FirstEnergy began accounting
for the effects of the Medicare Act  effective  January 1, 2004 as a result of a
February  2, 2004 plan  amendment  that  required  remeasurement  of the  plan's
obligations.  See Note 2 for a discussion  of the effect of the federal  subsidy
and plan amendment on the consolidated financial statements.

       FIN 46 (revised  December  2003),  "Consolidation  of  Variable  Interest
       Entities"

          In  December  2003,  the  FASB  issued  a  revised  interpretation  of
Accounting  Research  Bulletin  No.  51,  "Consolidated  Financial  Statements",
referred  to as  FIN  46R,  which  requires  the  consolidation  of a VIE  by an
enterprise if that enterprise is determined to be the primary beneficiary of the
VIE. As required,  JCP&L adopted FIN 46R for interests in VIEs commonly referred
to as  special-purpose  entities  effective  December 31, 2003 and for all other
types of entities  effective March 31, 2004.  Adoption of FIN 46R did not have a
material impact on JCP&L's financial  statements for the quarter ended March 31,
2004. See Note 2 for a discussion of Variable Interest Entities.

          For the quarter  ended March 31, 2004,  JCP&L  evaluated,  among other
entities,  its power purchase agreements and determined that it is possible that
six NUG entities  might be  considered  variable  interest  entities.  JCP&L has
requested but not received the information  necessary to determine whether these
entities are VIEs or whether  JCP&L is the primary  beneficiary.  In most cases,
the requested  information was deemed to be competitive and proprietary data. As
such,  JCP&L  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.  JCP&L's  purchased  power costs from these entities during the
first quarters of 2004 and 2003 were $28 million and $34 million,  respectively.
JCP&L is required to continue to make exhaustive efforts to obtain the necessary
information in future periods and is unable to determine the possible  impact of
consolidating any such entity without this information.

                                      114

<PAGE>
<TABLE>

                                            METROPOLITAN EDISON COMPANY

                                         CONSOLIDATED STATEMENTS OF INCOME
                                                    (Unaudited)

<CAPTION>
                                                                                          Three Months Ended
                                                                                                March 31,
                                                                                       -------------------------
                                                                                         2004             2003
                                                                                       ---------        --------
                                                                                             (In thousands)

<S>                                                                                   <C>              <C>
OPERATING REVENUES..............................................................      $ 260,898        $ 251,203
                                                                                      ---------        ---------

OPERATING EXPENSES AND TAXES:
   Purchased power..............................................................        143,456          135,291
   Other operating costs........................................................         33,048           33,735
                                                                                      ---------        ---------
       Total operation and maintenance expenses.................................        176,504          169,026
   Provision for depreciation and amortization..................................         35,395           34,108
   General taxes................................................................         17,736           16,860
   Income taxes.................................................................          7,980            7,198
                                                                                      ---------        ---------
       Total operating expenses and taxes.......................................        237,615          227,192
                                                                                      ---------        ---------


OPERATING INCOME................................................................         23,283           24,011


OTHER INCOME....................................................................          5,526            5,168
                                                                                      ---------        ---------


INCOME BEFORE NET INTEREST CHARGES..............................................         28,809           29,179
                                                                                      ---------        ---------


NET INTEREST CHARGES:
   Interest on long-term debt...................................................         10,147           10,539
   Allowance for borrowed funds used during construction........................            (71)             (73)
   Deferred interest............................................................             --             (440)
   Other interest expense.......................................................            689              463
   Subsidiary's preferred stock dividend requirements...........................             --            1,890
                                                                                      ---------        ---------
       Net interest charges.....................................................         10,765           12,379
                                                                                      ---------        ---------


INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE............................         18,044           16,800

Cumulative effect of accounting change (net of income taxes of $154,000) (Note 2)            --              217
                                                                                      ---------        ---------


NET INCOME......................................................................      $  18,044        $  17,017
                                                                                      =========        =========

<FN>
The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an
integral part of these statements.
</FN>

                                                         115

</TABLE>

<PAGE>

<TABLE>

                                            METROPOLITAN EDISON COMPANY

                                            CONSOLIDATED BALANCE SHEETS
                                                    (Unaudited)

<CAPTION>
                                                                                        March 31,       December 31,
                                                                                          2004             2003
                                                                                     -------------------------------
                                                                                              (In thousands)
                                         ASSETS
UTILITY PLANT:
<S>                                                                                    <C>              <C>
   In service.....................................................................     $1,847,899       $1,838,567
   Less-Accumulated provision for depreciation....................................        780,873          772,123
                                                                                       ----------       ----------
                                                                                        1,067,026        1,066,444
   Construction work in progress..................................................         20,599           21,980
                                                                                       ----------       ----------
                                                                                        1,087,625        1,088,424
                                                                                       ----------       ----------
OTHER PROPERTY AND INVESTMENTS:
   Nuclear plant decommissioning trusts...........................................        200,502          192,409
   Long-term notes receivable from associated companies...........................         10,636            9,892
   Other..........................................................................         33,814           34,922
                                                                                       ----------       ----------
                                                                                          244,952          237,223
                                                                                       ----------       ----------
CURRENT ASSETS:
   Cash and cash equivalents......................................................            120              121
   Receivables-
     Customers (less accumulated provisions of $4,886,000 and $4,943,000
        respectively, for uncollectible accounts).................................        114,964          118,933
     Associated companies.........................................................         48,939           45,934
     Notes receivable from associated companies...................................        126,525           10,467
     Other (less accumulated provisions of $21,000 and $68,000 respectively,
       for uncollectible accounts)................................................         17,947           22,750
   Prepayments and other..........................................................         43,201            6,600
                                                                                       ----------       ----------
                                                                                          351,696          204,805
                                                                                       ----------       ----------
DEFERRED CHARGES:
   Regulatory assets..............................................................        989,863        1,028,432
   Goodwill.......................................................................        880,468          884,279
   Other..........................................................................         32,381           30,824
                                                                                       ----------       ----------
                                                                                        1,902,712        1,943,535
                                                                                       ----------       ----------
                                                                                       $3,586,985       $3,473,987
                                                                                       ==========       ==========

                           CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
   Common stockholder's equity -
     Common stock, without par value, authorized 900,000 shares-
       859,500 shares outstanding.................................................     $1,298,130       $1,298,130
     Accumulated other comprehensive loss.........................................        (35,721)         (32,474)
     Retained earnings............................................................         40,055           27,011
                                                                                       ----------       ----------
       Total common stockholder's equity..........................................      1,302,464        1,292,667
   Long-term debt and other long-term obligations.................................        738,283          636,301
                                                                                       ----------       ----------
                                                                                        2,040,747        1,928,968
                                                                                       ----------       ----------
CURRENT LIABILITIES:
   Currently payable long-term debt...............................................        136,232           40,469
   Short-term borrowings -
     Associated companies.........................................................              -           65,335
   Accounts payable-
     Associated companies.........................................................         64,378           45,459
     Other........................................................................         21,807           33,878
   Accrued  taxes.................................................................          7,216            8,762
   Accrued interest...............................................................          7,383           11,848
   Other..........................................................................         23,242           22,162
                                                                                       ----------       ----------
                                                                                          260,258          227,913
                                                                                       ----------       ----------
NONCURRENT LIABILITIES:
   Accumulated deferred income taxes..............................................        295,962          297,140
   Accumulated deferred investment tax credits....................................         11,491           11,696
   Power purchase contract loss liability.........................................        551,598          584,340
   Nuclear fuel disposal costs....................................................         38,021           37,936
   Asset retirement obligation....................................................        213,261          210,178
   Pensions and other postretirement benefits.....................................        106,625          105,552
   Other..........................................................................         69,022           70,264
                                                                                       ----------       ----------
                                                                                        1,285,980        1,317,106
                                                                                        ---------       ----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 3)................................
                                                                                       ----------       ----------
                                                                                       $3,586,985       $3,473,987
                                                                                       ==========       ==========
<FN>
The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an
integral part of these balance sheets.
</FN>

                                                         116

</TABLE>

<PAGE>

<TABLE>

                                            METROPOLITAN EDISON COMPANY
                                       CONSOLIDATED STATEMENTS OF CASH FLOWS
                                                    (Unaudited)

<CAPTION>
                                                                                        Three Months Ended
                                                                                              March 31,
                                                                                    ---------------------------
                                                                                      2004               2003
                                                                                    ---------          --------
                                                                                            (In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
<S>                                                                                <C>                 <C>
Net income...................................................................      $  18,044           $ 17,017
   Adjustments to reconcile net income to net
     cash from operating activities-
       Provision for depreciation and amortization...........................         35,395             34,108
       Deferred costs, net...................................................        (16,792)           (10,767)
       Deferred income taxes, net............................................          2,639              1,385
       Amortization of investment tax credits................................           (206)              (205)
       Accrued retirement benefit obligation.................................          1,074                 --
       Accrued compensation, net.............................................           (634)              (104)
       Cumulative effect of accounting change (Note 2).......................             --               (371)
       Receivables...........................................................          5,767             18,344
       Materials and supplies................................................             18               (139)
       Accounts payable......................................................          6,848             31,968
       Accrued taxes.........................................................         (1,546)           (11,916)
       Accrued interest......................................................         (4,465)            (4,798)
       Prepayments and other current assets..................................        (36,618)           (30,140)
       Other.................................................................         (8,265)           (11,613)
                                                                                   ---------           --------
         Net cash provided from operating activities.........................          1,259             32,769
                                                                                   ---------           --------

CASH FLOWS FROM FINANCING ACTIVITIES:
   New Financing-
     Long-term debt..........................................................        247,607            247,696
   Redemptions and Repayments-
     Long-term debt..........................................................        (50,435)           (40,000)
     Short-term borrowings, net..............................................        (65,335)           (23,087)
   Dividend Payments-
     Common Stock............................................................         (5,000)                --
                                                                                   ----------          --------
       Net cash provided from financing activities...........................        126,837            184,609
                                                                                   ---------           --------

CASH FLOWS FROM INVESTING ACTIVITIES:
   Property additions........................................................         (8,962)           (10,333)
   Contributions to nuclear decommissioning trusts...........................         (2,371)            (2,371)
   Loans to associated companies, net........................................       (116,802)            (8,005)
   Other.....................................................................             38                217
                                                                                   ---------           --------
         Net cash used for investing activities..............................       (128,097)           (20,492)
                                                                                   ---------           --------

Net increase (decrease) in cash and cash equivalents.........................             (1)           196,886
Cash and cash equivalents at beginning of period ............................            121             15,685
                                                                                   ---------           --------
                                                                                   ---------           --------
Cash and cash equivalents at end of period...................................      $     120           $212,571
                                                                                   =========           ========


<FN>
The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an
integral part of these statements.
</FN>

                                                         117

</TABLE>

<PAGE>


                        REPORT OF INDEPENDENT ACCOUNTANTS


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,  2004,  and the  related
consolidated  statements  of income and cash  flows for each of the  three-month
periods ended March 31, 2004 and 2003.  These interim  financial  statements are
the responsibility of the Company's management.

We conducted our review in accordance with standards established by the American
Institute  of  Certified  Public  Accountants.  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 generally
accepted  auditing  standards,  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 auditing  standards  generally accepted
in the  United  States  of  America,  the  consolidated  balance  sheet  and the
consolidated  statement  of  capitalization  as of December  31,  2003,  and the
related  consolidated   statements  of  income,   common  stockholder's  equity,
preferred  stock,  cash flows and taxes for the year then  ended (not  presented
herein),  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 1(E) 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 8 to
those consolidated  financial  statements) dated February 25, 2004, we expressed
an  unqualified  opinion  on those  consolidated  financial  statements.  In our
opinion,  the information set forth in the accompanying  condensed  consolidated
balance sheet as of December 31, 2003, 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 7, 2004

                                      118

<PAGE>


                           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 provides  regulated  transmission  and  distribution  services in eastern
Pennsylvania.  Pennsylvania  customers  are  able to  choose  their  electricity
suppliers as a result of legislation  which  restructured  the electric  utility
industry. Met-Ed's regulatory plan required unbundling 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  and  maintains  PLR
obligations to customers who elect to retain Met-Ed as their power supplier.

Results of Operations
---------------------

          Net income in the first quarter of 2004  increased to $18 million from
$17 million in the first quarter of 2003.  Results improved in the first quarter
of 2004 due to increased  retail  electric  sales  revenues  and lower  interest
charges, partially offset by higher purchased power costs.

          Operating  revenues  increased  by $10  million,  or 3.9% in the first
quarter of 2004  compared with the first  quarter of 2003.  The higher  revenues
primarily  resulted  from  increased  distribution  revenues of $10 million from
electricity  throughput  as  a  result  of  higher  unit  prices  and  increased
consumption by the  commercial and industrial  sectors -- reflecting the effects
of an improving regional economy.

          Higher  retail  generation   kilowatt-hour  sales  of  7.9%  increased
operating  revenues  by $2  million.  The  increase  was  primarily  due to more
commercial  and  industrial  customers  returning  to Met-Ed  as their  electric
service  provider.  Sales of electric  generation by alternative  suppliers as a
percent of total sales  delivered in Met-Ed's  franchise area decreased to 10.3%
in the first  quarter of 2004 from 15.8% in the same  period of 2003.  Wholesale
revenues decreased by $1 million, reflecting lower sales to affiliated companies
and to the wholesale market.

          Changes  in  distribution  deliveries  in the  first  quarter  of 2004
compared to the first quarter 2003 are summarized in the following table:

                  Changes in Kilowatt-Hour Sales
                  ---------------------------------------------------
                  Increase (Decrease)
                  Distribution Deliveries:
                    Residential.............................    (0.6)%
                    Commercial..............................     3.9%
                    Industrial..............................     1.5%
                  ---------------------------------------------------
                  Total Distribution Deliveries.............     1.3%
                  ===================================================

       Operating Expenses and Taxes

          Total operating  expenses and taxes increased $10 million in the first
quarter of 2004 from the first  quarter of 2003.  Purchased  power costs were $8
million  higher due to increased PLR  kilowatt-hour  purchases  from FES (due to
increased   generation   sales   requirements),   partially  offset  by  reduced
above-market NUG costs.  Other operating costs were lower in 2004 in part due to
lower employee benefit costs. Depreciation and amortization expenses were higher
due to  increased  amortization  of  regulatory  assets  related to CTC  revenue
recovery. General taxes increased due to gross receipts taxes and higher payroll
taxes related to the transfer of employees to Met-Ed from GPUS.

       Net Interest Charges

          Net  interest  charges  continued  to trend  lower,  decreasing  by $2
million  in the  first  quarter  of 2004  from the same  quarter  of last  year,
reflecting  redemptions and  refinancings  since the end of the first quarter of
2003.

       Cumulative Effect of Accounting Change

          Upon  adoption  of SFAS  143 in the  first  quarter  of  2003,  Met-Ed
recorded  an  after-tax  credit  to  net  income  of  $217,000.  The  cumulative
adjustment for  unrecognized  depreciation and accretion offset by the reduction
in the existing  decommissioning  liabilities was a $371,000 increase to income,
or $217,000 net of income taxes.

                                      119

<PAGE>

Capital Resources and Liquidity
-------------------------------

          Met-Ed  expects to meet its cash  requirements  in 2004 for  operating
expenses, construction expenditures, scheduled debt maturities and optional debt
redemptions  without  increasing its net debt and preferred  stock  outstanding.
Over the next three years,  Met-Ed expects to meet its  contractual  obligations
with cash from  operations.  Thereafter,  Met-Ed expects to use a combination of
cash from operations and funds from the capital markets.

       Changes in Cash Position

          As of March 31, 2004, Met-Ed had $120,000 of cash and cash equivalents
compared with $121,000 as of December 31, 2003. The major sources for changes in
these balances are summarized below.

       Cash Flows From Operating Activities

          Cash provided from  operating  activities in the first quarter of 2004
and 2003 were as follows:

          Operating Cash Flows                     2004          2003
          -------------------------------------------------------------
                                                      (In millions)

          Cash earnings (1)....................     $ 39         $ 41
          Working capital and other............      (38)          (8)
          -------------------------------------------------------------

          Total................................      $ 1         $ 33
          =============================================================

          (1) Includes net income, depreciation and amortization, deferred
              costs  recoverable  as regulatory  assets,  deferred  income
              taxes, investment tax credits and major noncash credits.

          Net cash provided from operating  activities  decreased $32 million in
the first  quarter  of 2004 from the first  quarter of 2003 as a result of a $30
million  decrease  from  working  capital  and other  changes  and a $2  million
decrease in cash  earnings.  The largest  factor  contributing  to the change in
working capital was a $25 million decrease in accounts payable.

       Cash Flows From Financing Activities

          In the  first  quarter  of 2004,  net  cash  provided  from  financing
activities  of $127  million  reflected  the  issuance of $250 million of senior
notes,  partially  offset by the redemption of $50 million of long-term debt and
$65 million of  short-term  debt,  and a common stock  dividend of $5 million to
FirstEnergy. Net cash provided from financing activities totaled $185 million in
the first quarter of 2003,  due to the issuance of $250 million of senior notes,
partially  offset by the  redemption  of $40 million of  long-term  debt and $23
million of short-term debt.

          As of March 31, 2004,  Met-Ed had  approximately  $127 million of cash
and temporary  investments  (which  include  short-term  notes  receivable  from
associated companies) and no outstanding short-term borrowings.  Met-Ed will not
issue first mortgage bonds since its senior note indentures prohibit (subject to
certain  exceptions)  it from  issuing  any debt  which is senior to the  senior
notes.  Because Met-Ed satisfied the provisions of its senior note indenture for
the release of all FMBs held as collateral for senior notes in March 2004, it is
no longer  required to issue FMBs as collateral  for future  issuances of senior
notes and  therefore  not limited as to the amount of senior notes it may issue.
Met-Ed had no restrictions on the issuance of preferred stock.

          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.
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 in the first quarter of 2004 was 1.30%.

          In March  2004,  Met-Ed  completed  an  on-balance  sheet,  receivable
financing transaction which allows it to borrow up to $80 million. The borrowing
rate is based on bank  commercial  paper  rates.  Met-Ed is  required  to pay an
annual  facility  fee of 0.30% on the entire  finance  limit.  The  facility was
undrawn as of March 31, 2004. This facility matures on March 29, 2005.

          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 of its securities is stable.

                                      120

<PAGE>

          On February 6, 2004, Moody's  downgraded  FirstEnergy senior unsecured
debt to Baa3 from Baa2 and downgraded  the senior secured debt of JCP&L,  Met-Ed
and Penelec to Baa1 from A2. Moody's also  downgraded the preferred stock rating
of JCP&L to Ba1 from Baa2 and the  senior  unsecured  rating of  Penelec to Baa2
from A2. The ratings of OE, CEI, TE and Penn were  confirmed.  Moody's said that
the  lower  ratings  were  prompted  by:  "1) high  consolidated  leverage  with
significant  holding company debt, 2) a degree of regulatory  uncertainty in the
service  territories in which the company  operates,  3) risks  associated  with
investigations of the causes of the August 2003 blackout, and related securities
litigation,  and 4) a  narrowing  of  the  ratings  range  for  the  FirstEnergy
operating utilities,  given the degree to which FirstEnergy increasingly manages
the utilities as a single system and the significant financial interrelationship
among the subsidiaries."

          On March 9, 2004, S&P stated that the NRC's permission for FirstEnergy
to restart the Davis-Besse nuclear plant was positive for credit quality because
it would positively affect cash flow by eliminating  replacement power costs and
"demonstrating   management's  ability  to  overcome  operational   challenges."
However, S&P did not change  FirstEnergy's  ratings or outlook because it stated
that financial performance still "significantly lags expectations and management
faces other operational hurdles."

       Cash Flows From Investing Activities

          In the first  quarter of 2004,  net cash used in investing  activities
totaled $128 million,  compared to $20 million in the first quarter of 2003. The
change  resulted  from a $108 million  increase in loan  payments to  associated
companies offset in part by slightly lower property additions.  Expenditures for
property additions primarily support Met-Ed's energy delivery operations.

          During  the  remaining  quarters  of 2004,  capital  requirements  for
property  additions are expected to be about $46 million.  Met-Ed has additional
requirements of  approximately  $136 million for maturing  long-term debt during
the remainder of 2004. These cash requirements are expected to be satisfied from
internal cash and short-term credit arrangements.

Off-Balance Sheet Arrangements
------------------------------

          As of March 31, 2004,  off-balance sheet arrangements  include certain
statutory business trusts created by Met-Ed to issue trust preferred  securities
aggregating  $93  million.  These  trusts  were  included  in  the  consolidated
financial  statements  of  Met-Ed  prior to the  adoption  of FIN 46R,  but have
subsequently been  deconsolidated  under FIN 46R (see Note 2 - Variable Interest
Entities). Deconsolidation has not resulted in any change in outstanding debt.

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 executive officers, exercises
an independent risk oversight  function to ensure compliance with corporate risk
management policies and prudent risk management practices.

       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 future  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. The change in
the fair value of commodity  derivative  contracts  related to energy production
during the first quarter of 2004 is summarized in the following table:

                                      121

<PAGE>

<TABLE>

Increase (Decrease) in the Fair Value
of Commodity Derivative Contracts
<CAPTION>
                                                                Non-Hedge     Hedge      Total
--------------------------------------------------------------------------------------------------
                                                                           (In millions)
Change in the Fair Value of Commodity Derivative Contracts
<S>                                                                <C>         <C>       <C>
Outstanding net asset as of January 1, 2004...................     $ 31        $ --      $ 31
New contract value when entered...............................       --          --        --
Additions/change in value of existing contracts...............       (1)         --        (1)
Change in techniques/assumptions..............................       --          --        --
Settled contracts.............................................       --          --        --
-------------------------------------------------------------------------------------------------
Net Assets - Derivatives Contracts as of March 31, 2004 (1)...     $ 30        $ --      $ 30
=================================================================================================

Impact of Changes in Commodity Derivative Contracts (2)
Income Statement Effects (Pre-Tax)............................     $ --        $ --      $ --
Balance Sheet Effects:
Other Comprehensive Income (Pre-Tax)..........................     $ --        $ --      $ --
Regulatory Liability..........................................     $ (1)       $ --      $ (1)

</TABLE>

(1)  Includes $30 million in non-hedge commodity derivative contracts which
     are offset by a regulatory  liability.
(2)  Represents  the  increase  in value  of  existing  contracts,  settled
     contracts and changes in techniques/assumptions.

Derivatives included on the Consolidated Balance Sheet as of March 31, 2004:

                                                   Non-Hedge   Hedge    Total
          -------------------------------------------------------------------
                                                             (In millions)
          Current-
                Other Assets......................    $--      $  --      $--

          Non-Current-
                Other Deferred Charges............     30         --       30
          -------------------------------------------------------------------

                Net assets........................    $30      $  --      $30
          ===================================================================

          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.  Sources  of  information  for  the  valuation  of
derivative contracts by year are summarized in the following table:
<TABLE>

<CAPTION>
Source of Information
- Fair Value by Contract Year            2004       2005      2006        2007       Thereafter    Total
---------------------------------------------------------------------------------------------------------
                                                                 (In millions)
<S>                                      <C>        <C>       <C>         <C>             <C>        <C>
Prices based on external sources(1)      $ 3        $ 5       $ --        $ --            $--        $ 8
Prices based on models                    --         --          5           5             12         22
---------------------------------------------------------------------------------------------------------

    Total(2)                             $ 3        $ 5        $ 5         $ 5            $12        $30
=========================================================================================================
</TABLE>

(1)  Broker quote sheets.
(2)  Includes $30 million from an embedded option that is offset by a regulatory
     liability and does not affect earnings.

          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, 2004.

       Equity Price Risk

          Included in Met-Ed's  nuclear  decommissioning  trust  investments are
marketable equity securities carried at their market value of approximately $119
million  and  $114  million  as  of  March  31,  2004  and  December  31,  2003,
respectively.  A hypothetical  10% decrease in prices quoted by stock  exchanges
would result in a $12 million reduction in fair value as of March 31, 2004.

Outlook
-------

          Beginning  in 1999,  all of  Met-Ed's  customers  were  able to select
alternative  energy  suppliers.  Met-Ed  continues to deliver power to homes and
businesses through its existing  distribution  system,  which remains regulated.
The PPUC authorized  Met-Ed's rate  restructuring  plan,  establishing  separate
charges for transmission,  distribution,  generation and stranded cost recovery,
which is  recovered  through a CTC.  Customers  electing to obtain power from an
alternative  supplier have their bills reduced based on the regulated generation
component,  and the customers  receive a generation  charge from the alternative

                                      122


<PAGE>

supplier.  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, which is referred to as its PLR obligation.

          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. All of Met-Ed's
regulatory  assets are expected to continue to be recovered under the provisions
of its  regulatory  plan.  Met-Ed's  regulatory  assets totaled $990 million and
$1.03 billion as of March 31, 2004 and December 31, 2003, respectively.

       Regulatory Matters

          In June 2001, the PPUC approved the Settlement Stipulation with all of
the major parties in the combined merger and rate proceedings which approved the
FirstEnergy/GPU merger and provided PLR deferred accounting treatment for energy
costs,  permitting Met-Ed to defer, for future recovery,  energy costs in excess
of amounts  reflected in its capped  generation rates  retroactive to January 1,
2001.  This PLR deferral  accounting  procedure was later reversed in a February
2002 Commonwealth  Court of Pennsylvania  decision.  The court decision affirmed
the PPUC decision  regarding  approval of the merger,  remanding the decision to
the PPUC only with respect to the issue of merger savings.  Met-Ed established a
$103.0 million  reserve in 2002 for its PLR deferred energy costs incurred prior
to its  acquisition by FirstEnergy,  reflecting the potential  adverse impact of
the then  pending  Pennsylvania  Supreme  Court  decision  whether to review the
Commonwealth Court decision.  The reserve increased goodwill by an aggregate net
of tax amount of $60.3 million.

          On April 2,  2003,  the PPUC  remanded  the issue  relating  to merger
savings to the ALJ for hearings, directed Met-Ed to file a position paper on the
effect of the Commonwealth Court order on the Settlement Stipulation and allowed
other  parties to file  responses to the position  paper.  Met-Ed filed a letter
with the ALJ on June 11,  2003,  voiding the  Stipulation  in its  entirety  and
reinstating Met-Ed's restructuring settlement previously approved by the PPUC.

          On October  2,  2003,  the PPUC  issued an order  concluding  that the
Commonwealth Court reversed the PPUC's June 20, 2001 order in its entirety.  The
PPUC directed  Met-Ed to file tariffs within thirty days of the order to reflect
the CTC rates and  shopping  credits  that were in effect  prior to the June 21,
2001 order to be  effective  upon one day's  notice.  In response to that order,
Met-Ed filed these  supplements to its tariffs to become  effective  October 24,
2003.

          On October 8, 2003, Met-Ed filed a petition for clarification relating
to the October 2, 2003 order on two issues:  to  establish  June 30, 2004 as the
date to fully  refund  the NUG  trust  fund  and to  clarify  that  the  ordered
accounting  treatment regarding the CTC rate/shopping  credit swap should follow
the  ratemaking,  and that the  PPUC's  findings  would not impair its rights to
recover all of its stranded costs. On October 9, 2003,  ARIPPA (an intervenor in
the  proceedings)  petitioned the PPUC to direct Met-Ed to reinstate  accounting
for the CTC  rate/shopping  credit swap retroactive to January 1, 2002.  Several
other  parties  also filed  petitions.  On October 16,  2003,  the PPUC issued a
reconsideration  order  granting the date  requested by Met-Ed for the NUG trust
fund refund and,  denying  Met-Ed's  other  clarification  requests and granting
ARIPPA's  petition with respect to the retroactive  accounting  treatment of the
changes to the CTC rate/shopping  credit swap. On October 22, 2003, Met-Ed filed
an  Objection  with the  Commonwealth  Court  asking that the Court  reverse the
PPUC's finding that requires  Met-Ed to treat the stipulated CTC rates that were
in effect from January 1, 2002 on a retroactive basis.

          On October 27,  2003,  one  Commonwealth  Court judge  issued an Order
denying  Met-Ed's  objection  without  explanation.  Due to the vagueness of the
Order,  Met-Ed, on October 31, 2003, filed an Application for Clarification with
the judge. Concurrent with this filing, Met-Ed, in order to preserve its rights,
also filed with the Commonwealth  Court both a Petition for Review of the PPUC's
October 16 and October 22 Orders,  and an  application  for  reargument,  if the
judge,  in his  clarification  order,  indicates  that  Met-Ed's  objection  was
intended to be denied on the merits.  In addition to these findings,  Met-Ed, in
compliance with the PPUC's Orders,  filed revised PPUC quarterly reports for the
twelve months ended  December 31, 2001 and 2002,  and for the first two quarters
of 2003,  reflecting  balances  consistent  with the  PPUC's  findings  in their
Orders.

          Effective  September 1, 2002,  Met-Ed  agreed to purchase a portion of
its PLR requirements from FES through a wholesale power sale agreement.  The PLR
sale will be 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 assumed 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. FES has
hedged  most of Met-Ed's  unfilled  PLR on-peak  obligation  through  2004 and a
portion of 2005,  the period during which  deferred  accounting  was  previously
allowed  under the PPUC's  order.  Met-Ed is  authorized  to continue  deferring
differences between NUG contract costs and current market prices.

                                      123

<PAGE>

          In late 2003,  the PPUC  issued a  Tentative  Order  implementing  new
reliability  benchmarks  and  standards.  In  connection  therewith,   the  PPUC
commenced a  rulemaking  procedure  to amend the  Electric  Service  Reliability
Regulations to implement these new benchmarks,  and create additional  reporting
on  reliability.  Although  neither  the  Tentative  Order  nor the  Reliability
Rulemaking has been finalized,  the PPUC ordered all  Pennsylvania  utilities to
begin filing quarterly  reports on November 1, 2003. The comment period for both
the  Tentative  Order and the Proposed  Rulemaking  Order has closed.  Met-Ed is
currently  awaiting the PPUC to issue a final order in both  matters.  The order
will  determine  (1) the standards  and  benchmarks to be utilized,  and (2) the
details required in the quarterly and annual reports.

          On January 16,  2004,  the PPUC  initiated a formal  investigation  of
whether Met-Ed's "service reliability performance  deteriorated to a point below
the  level of  service  reliability  that  existed  prior to  restructuring"  in
Pennsylvania.  Discovery has commenced in the proceeding and Met-Ed's  testimony
is due May 14,  2004.  Hearings  are  scheduled  to begin August 3, 2004 in this
investigation  and the ALJ has been directed to issue a Recommended  Decision by
September  30,  2004,  in order to allow the PPUC time to issue a Final Order by
year end of 2004.  Met-Ed is unable to predict the outcome of the  investigation
or the impact of the PPUC order.

         Environmental Matters

          Met-Ed  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 be held  liable  on a joint and  several  basis.  Therefore,  environmental
liabilities   that  are  considered   probable  have  been   recognized  on  the
Consolidated  Balance Sheets,  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.  Met-Ed  has  accrued  liabilities
aggregating   approximately  $50,000  as  of  March  31,  2004.  Met-Ed  accrues
environmental  liabilities only when it can conclude that it is probable that an
obligation for such costs exists and can reasonably determine the amount of such
costs.   Unasserted   claims  are   reflected  in  Met-Ed's   determination   of
environmental  liabilities  and are  accrued  in the  period  that they are both
probable and reasonably estimable.

       Power Outage

          On August  14,  2003,  various  states  and parts of  southern  Canada
experienced a widespread power outage.  That outage affected  approximately  1.4
million  customers in  FirstEnergy's  service area.  On April 5, 2004,  the U.S.
-Canada Power System Outage Task Force released its final report on this outage.
The final report supercedes the interim report that had been issued in November,
2003. In the final report,  the Task Force concluded,  among other things,  that
the problems  leading to the outage began in  FirstEnergy's  Ohio service  area.
Specifically,   the  final  report  concludes,  among  other  things,  that  the
initiation of the August 14th power outage resulted from the coincidence on that
afternoon of several events,  including,  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 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 14th power outage and that it does not
adequately  address the  underlying  causes of the outage.  FirstEnergy  remains
convinced  that the outage  cannot be explained  by events on any one  utility's
system. The final report contains 46 "recommendations to prevent or minimize the
scope of future blackouts."  Forty-five of those recommendations relate to broad
industry  or policy  matters  while one  relates  to  activities  the Task Force
recommends be undertaken by FirstEnergy,  MISO,  PJM, and ECAR.  FirstEnergy has
undertaken  several  initiatives,  some prior to and some since the August  14th
power outage,  to enhance  reliability which are consistent with these and other
recommendations  and believes it will complete  those relating to summer 2004 by
June 30 (see  Reliability  Initiatives  below).  As  many of  these  initiatives
already were in process and budgeted in 2004,  FirstEnergy does not believe that
any  incremental  expenses  associated with  additional  initiatives  undertaken
during 2004 will have a material effect on its operations or financial  results.
FirstEnergy  notes,   however,  that  the  applicable  government  agencies  and
reliability   coordinators   may  take  a  different   view  as  to  recommended
enhancements or may recommend  additional  enhancements in the future that could
require additional, material expenditures.

       Reliability Initiatives

          On  October  15,  2003,  NERC  issued a Near  Term  Action  Plan  that
contained  recommendations  for all control areas and  reliability  coordinators
with  respect  to  enhancing  system   reliability.   Approximately  20  of  the
recommendations  were directed at the FirstEnergy  companies and broadly focused
on  initiatives  that are  recommended  for  completion  by summer  2004.  These
initiatives  principally  relate to  changes in voltage  criteria  and  reactive
resources  management;  operational  preparedness  and action  plans;  emergency
response   capabilities;   and,  preparedness  and  operating  center  training.

                                      124

<PAGE>

FirstEnergy   presented  a  detailed   compliance  plan  to  NERC,   which  NERC
subsequently  endorsed on May 7, 2004, and the various  initiatives are expected
to be completed no later than June 30, 2004.

          On February 26-27, 2004, certain FirstEnergy companies participated in
a NERC Control Area Readiness Audit. This audit, part of an announced program by
NERC to review  control area  operations  throughout  much of the United  States
during 2004, is an  independent  review to identify areas for  improvement.  The
final  audit  report was  completed  on April 30,  2004.  The report  identified
positive  observations  and included  various  recommendations  for improvement.
FirstEnergy  is currently  reviewing the audit results and  recommendations  and
expects to  implement  those  relating to summer  2004 by June 30.  Based on its
review thus far, FirstEnergy believes that none of the recommendations  identify
a  need  for  any  incremental  material  investment  or  upgrades  to  existing
equipment.  FirstEnergy notes, however, that NERC 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.

          On March 1, 2004, certain  FirstEnergy  companies filed, in accordance
with a November 25, 2003 order from the PUCO, their plan for addressing  certain
issues  identified  by the PUCO from the U.S. - Canada Power System  Outage Task
Force  interim  report.  In  particular,   the  filing  addressed   upgrades  to
FirstEnergy's  control room computer  hardware and software and  enhancements to
the  training of control  room  operators.  The PUCO will review the plan before
determining the next steps, if any, in the proceeding.

          On April 22,  2004,  FirstEnergy  filed  with FERC the  results of the
FERC-ordered independent study of part of Ohio's power grid. The study examined,
among other things,  the reliability of the transmission grid in critical points
in  the  Northern  Ohio  area  and  the  need,   if  any,  for  reactive   power
reinforcements  during summer 2004 and 2005.  FirstEnergy is currently reviewing
the  results  of that  study and  expects  to  complete  the  implementation  of
recommendations  relating to 2004 by this summer.  Based on its review thus far,
FirstEnergy  believes that the study does not recommend any incremental material
investment or 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.

          With respect to each of the  foregoing  initiatives,  FirstEnergy  has
requested and NERC has agreed to provide, a technical assistance team of experts
to provide ongoing guidance and assistance in implementing and confirming timely
and successful completion.

       Legal Matters

          Various  lawsuits,  claims  and  proceedings  related  to  our  normal
business  operations are pending against Met-Ed,  the most  significant of which
are described above.

Critical Accounting Policies

          Met-Ed prepares its  consolidated  financial  statements in accordance
with GAAP.  Application  of these  principles  often  requires a high  degree of
judgment,  estimates  and  assumptions  that affect  financial  results.  All of
Met-Ed's  assets are subject to their own specific risks and  uncertainties  and
are regularly reviewed for impairment.  Assets related to the application of the
policies   discussed   below  are  similarly   reviewed  with  their  risks  and
uncertainties  reflecting  these  specific  factors.  Met-Ed's more  significant
accounting policies are described below.

       Regulatory Accounting

          Met-Ed is subject  to  regulation  that sets the prices  (rates) it is
permitted to charge its customers  based on costs that the  regulatory  agencies
determine Met-Ed is permitted to recover. At times, regulators permit the future
recovery through rates of costs that would be currently charged to expense by an
unregulated  company.  This  rate-making  process  results in the  recording  of
regulatory assets based on anticipated  future cash inflows.  As a result of the
changing  regulatory   framework  in  Pennsylvania,   a  significant  amount  of
regulatory assets have been recorded - $990 million as of March 31, 2004. Met-Ed
regularly  reviews these assets to assess their ultimate  recoverability  within
the approved regulatory guidelines. Impairment risk associated with these assets
relates to potentially  adverse  legislative,  judicial or regulatory actions in
the future.

       Derivative Accounting

          Determination  of appropriate  accounting for derivative  transactions
requires the involvement of management representing operations, finance and risk
assessment.  In order to determine the  appropriate  accounting  for  derivative
transactions,  the  provisions of the contract need to be carefully  assessed in
accordance  with  the  authoritative   accounting  literature  and  management's
intended use of the derivative.  New authoritative  guidance  continues to shape
the  application  of  derivative  accounting.   Management's   expectations  and
intentions  are key factors in  determining  the  appropriate  accounting  for a
derivative  transaction and, as a result,  such  expectations and intentions are

                                      125

<PAGE>

documented. Derivative contracts that are determined to fall within the scope of
SFAS 133, as amended, must be recorded at their fair value. Active market prices
are not always  available  to  determine  the fair value of the later years of a
contract,  requiring  that various  assumptions  and  estimates be used in their
valuation.  Met-Ed continually monitors its derivative contracts to determine if
its  activities,  expectations,  intentions,  assumptions  and estimates  remain
valid. As part of its normal operations, Met-Ed enters into commodity contracts,
as well as  interest  rate  swaps,  which  increase  the  impact  of  derivative
accounting judgments.

       Revenue Recognition

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

       Pension and Other Postretirement Benefits Accounting

          FirstEnergy's  reported  costs of providing  non-contributory  defined
pension benefits and  postemployment  benefits other than pensions are dependent
upon  numerous  factors  resulting  from  actual  plan  experience  and  certain
assumptions.

          Pension  and  OPEB  costs  are   affected  by  employee   demographics
(including  age,  compensation  levels,  and employment  periods),  the level of
contributions  FirstEnergy makes to the plans, and earnings on plan assets. Such
factors may be further affected by business  combinations (such as FirstEnergy's
merger with GPU in November 2001),  which impacts  employee  demographics,  plan
experience  and other  factors.  Pension  and OPEB  costs are also  affected  by
changes  to key  assumptions,  including  anticipated  rates of  return  on plan
assets,  the discount rates and health care trend rates used in determining  the
projected benefit obligations for pension and OPEB costs.

          In accordance  with SFAS 87 and SFAS 106,  changes in pension and OPEB
obligations  associated with these factors may not be immediately  recognized as
costs on the income statement, but generally are recognized in future years over
the remaining average service period of plan participants.  SFAS 87 and SFAS 106
delay  recognition  of changes due to the  long-term  nature of pension and OPEB
obligations and the varying market  conditions likely to occur over long periods
of time. As such, significant portions of pension and OPEB costs recorded in any
period  may not  reflect  the actual  level of cash  benefits  provided  to plan
participants and are significantly influenced by assumptions about future market
conditions and plan participants' experience.

          In selecting an assumed discount rate, FirstEnergy considers currently
available rates of return on high-quality fixed income  investments  expected to
be   available   during  the  period  to  maturity  of  the  pension  and  other
postretirement  benefit  obligations.  Due to recent  declines in corporate bond
yields and interest rates in general,  FirstEnergy  reduced the assumed discount
rate as of December 31, 2003 to 6.25% from 6.75% used as of December 31, 2002.

          FirstEnergy's  assumed rate of return on pension plan assets considers
historical  market  returns and economic  forecasts for the types of investments
held by its pension trusts.  In 2003 and 2002, plan assets actually earned 24.0%
and (11.3)%,  respectively.  FirstEnergy's  pension  costs in 2003 and the first
quarter  of 2004 were  computed  assuming  a 9.0% rate of return on plan  assets
based upon  projections  of future  returns  and its  pension  trust  investment
allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash.

          Based on pension  assumptions  and pension  plan assets as of December
31, 2003,  FirstEnergy  will not be required to fund its pension  plans in 2004.
However,  health care cost trends have  significantly  increased and will affect
future  OPEB  costs.  The  2004  and  2003  composite  health  care  trend  rate
assumptions are approximately 10%-12% gradually decreasing to 5% in later years.
In determining  its trend rate  assumptions,  FirstEnergy  included the specific
provisions of its health care plans, the  demographics and utilization  rates of
plan participants,  actual cost increases  experienced in its health care plans,
and projections of future medical trend rates.

       Long-Lived Assets

          In  accordance  with  SFAS  144,  Met-Ed  periodically  evaluates  its
long-lived assets to determine whether conditions exist that would indicate that
the carrying  value of an asset might not be fully  recoverable.  The accounting
standard requires that if the sum of future cash flows  (undiscounted)  expected
to result from an asset is less than the carrying  value of the asset,  an asset
impairment  must be recognized in the financial  statements.  If impairment  has

                                      126

<PAGE>

occurred,  Met-Ed  recognizes a loss - calculated as the difference  between the
carrying value and the estimated fair value of the asset (discounted  future net
cash flows).

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

       Nuclear Decommissioning

          In accordance with SFAS 143,  Met-Ed  recognizes an ARO for the future
decommissioning  of TMI-2. The ARO liability  represents an estimate of the fair
value of Met-Ed's current obligation related to nuclear decommissioning.  A fair
value measurement  inherently  involves  uncertainty in the amount and timing of
settlement  of the  liability.  Met-Ed used an expected  cash flow  approach (as
discussed  in FASB  Concepts  Statement  No. 7) to measure the fair value of the
nuclear  decommissioning  ARO. This approach  applies  probability  weighting to
discounted future cash flow scenarios that reflect a range of possible outcomes.

       Goodwill

          In a business  combination,  the excess of the purchase price over the
estimated  fair  values  of the  assets  acquired  and  liabilities  assumed  is
recognized  as  goodwill.  Based on the  guidance  provided by SFAS 142,  Met-Ed
evaluates  goodwill  for  impairment  at least  annually  and would make such an
evaluation  more  frequently  if  indicators  of  impairment  should  arise.  In
accordance with the accounting  standard,  if the fair value of a reporting unit
is less than its carrying value (including goodwill), the goodwill is tested for
impairment. If impairment were to be indicated,  Met-Ed would recognize a loss -
calculated as the difference  between the implied fair value of its goodwill and
the carrying value of the goodwill.  Met-Ed's annual review was completed in the
third quarter of 2003,  with no  impairment  indicated.  The  forecasts  used in
Met-Ed's evaluations of goodwill reflect operations  consistent with its general
business  assumptions.  Unanticipated  changes in those assumptions could have a
significant  effect on Met-Ed's  future  evaluations  of goodwill.  In the first
quarter of 2004,  Met-Ed reduced goodwill by $4 million for interest received on
a pre-merger income tax refund. As of March 31, 2004, Met-Ed had $880 million of
goodwill.

New Accounting Standards and Interpretations
--------------------------------------------

       FSP  106-1,  "Accounting  and  Disclosure  Requirements  Related  to  the
       Medicare Prescription Drug, Improvement and Modernization Act of 2003"

          Issued   January  12,  2004,   FSP  106-1   permits  a  sponsor  of  a
postretirement  health care plan that  provides a  prescription  drug benefit to
make a one-time  election to defer  accounting  for the effects of the  Medicare
Act.  FirstEnergy  elected to defer the effects of the  Medicare  Act due to the
lack of specific guidance.  Pursuant to FSP 106-1,  FirstEnergy began accounting
for the effects of the Medicare Act  effective  January 1, 2004 as a result of a
February  2, 2004 plan  amendment  that  required  remeasurement  of the  plan's
obligations.  See Note 2 for a discussion  of the effect of the federal  subsidy
and plan amendment on the consolidated financial statements.

       FIN 46 (revised  December  2003),  "Consolidation  of  Variable  Interest
       Entities"

          In  December  2003,  the  FASB  issued  a  revised  interpretation  of
Accounting  Research  Bulletin  No.  51,  "Consolidated  Financial  Statements",
referred  to as  FIN  46R,  which  requires  the  consolidation  of a VIE  by an
enterprise if that enterprise is determined to be the primary beneficiary of the
VIE. As required, Met-Ed adopted FIN 46R for interests in VIEs commonly referred
to as  special-purpose  entities  effective  December 31, 2003 and for all other
types of entities  effective March 31, 2004.  Adoption of FIN 46R did not have a
material impact on Met-Ed's financial statements for the quarter ended March 31,
2004. See Note 2 for a discussion of Variable Interest Entities.

          For the quarter ended March 31, 2004,  Met-Ed  evaluated,  among other
entities,  its power purchase agreements and determined that it is possible that
one NUG entity  might be  considered  a  variable  interest  entity.  Met-Ed has
requested but not received the information  necessary to determine  whether this
entity is a VIE or whether Met-Ed is the primary beneficiary. In most cases, the
requested  information  was deemed to be competitive  and  proprietary  data. As
such,  Met-Ed  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. Met-Ed's purchased power costs from this entity during the first
quarters of 2004 and 2003 were $16 million and $15 million, respectively. Met-Ed
is  required  to continue  to make  exhaustive  efforts to obtain the  necessary
information in future periods and is unable to determine the possible  impact of
consolidating any such entity without this information.

                                      127

<PAGE>

<TABLE>

                                           PENNSYLVANIA ELECTRIC COMPANY

                                         CONSOLIDATED STATEMENTS OF INCOME
                                                    (Unaudited)

<CAPTION>
                                                                                          Three Months Ended
                                                                                                March 31,
                                                                                     ---------------------------
                                                                                        2004             2003
                                                                                     ----------       ----------
                                                                                             (In thousands)

<S>                                                                                  <C>              <C>
OPERATING REVENUES..............................................................     $  256,445       $  254,876
                                                                                     ----------       ----------


OPERATING EXPENSES AND TAXES:
   Purchased power..............................................................        156,376          155,146
   Other operating costs........................................................         39,908           43,077
                                                                                     ----------       ----------
       Total operation and maintenance expenses.................................        196,284          198,223
   Provision for depreciation and amortization..................................         25,089           25,337
   General taxes................................................................         16,962           15,744
   Income taxes.................................................................          2,563            2,893
                                                                                     ----------       ----------
       Total operating expenses and taxes.......................................        240,898          242,197
                                                                                     ----------       ----------


OPERATING INCOME................................................................         15,547           12,679


OTHER EXPENSE...................................................................            (84)            (192)
                                                                                     -----------      ----------


INCOME BEFORE NET INTEREST CHARGES..............................................         15,463           12,487
                                                                                     ----------       ----------


NET INTEREST CHARGES:
   Interest on long-term debt...................................................          7,447            7,339
   Allowance for borrowed funds used during construction........................            (70)             (81)
   Deferred interest............................................................            190             (996)
   Other interest expense ......................................................          2,237              143
   Subsidiary's preferred stock dividend requirements...........................             --            1,888
                                                                                     ----------       ----------
       Net interest charges.....................................................          9,804            8,293
                                                                                     ----------       ----------


INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE............................          5,659            4,194

Cumulative effect of accounting change (net of income taxes of $777,000) (Note 2)            --            1,096
                                                                                     ----------       ----------


NET INCOME......................................................................     $    5,659       $    5,290
                                                                                     ==========       ==========


<FN>
The preceding Notes to Consolidated Financial Statements as they relate to the Pennsylvania Electric Company are
an integral part of these statements.
</FN>

                                                         128

</TABLE>

<PAGE>

<TABLE>

                                           PENNSYLVANIA ELECTRIC COMPANY

                                            CONSOLIDATED BALANCE SHEETS
                                                   (Unaudited)

<CAPTION>
                                                                                        March 31,       December 31,
                                                                                          2004             2003
                                                                                     -------------------------------
                                                                                              (In thousands)
                                         ASSETS
UTILITY PLANT:
<S>                                                                                    <C>              <C>
   In service.....................................................................     $1,976,743       $1,966,624
   Less-Accumulated provision for depreciation....................................        796,606          785,715
                                                                                       ----------       ----------
                                                                                        1,180,137        1,180,909
   Construction work in progress..................................................         29,374           29,063
                                                                                       ----------       ----------
                                                                                        1,209,511        1,209,972
                                                                                       ----------       ----------
OTHER PROPERTY AND INVESTMENTS:
   Non-utility generation trusts..................................................         94,660           43,864
   Nuclear plant decommissioning trusts...........................................        105,615          102,673
   Long-term notes receivable from associated companies...........................         13,865           13,794
   Other..........................................................................         19,117           19,635
                                                                                       ----------       ----------
                                                                                          233,257          179,966
                                                                                        ---------       ----------
CURRENT ASSETS:
   Cash and cash equivalents......................................................             36               36
   Receivables-
     Customers (less accumulated provisions of $5,872,000 and $5,833,000
       respectively, for uncollectible accounts)..................................        117,489          124,462
     Associated companies.........................................................        107,346           88,598
     Other (less accumulated provisions of $388,000 and $399,000
       respectively, for uncollectible accounts)..................................         16,121           15,767
   Prepayments and other..........................................................         49,564            2,511
                                                                                       ----------       ----------
                                                                                          290,556          231,374
                                                                                       ----------       ----------
DEFERRED CHARGES:
   Regulatory assets..............................................................        458,560          497,219
   Goodwill.......................................................................        894,491          898,547
   Accumulated deferred income tax benefits.......................................              -           16,642
   Other..........................................................................         19,568           18,523
                                                                                       ----------       ----------
                                                                                        1,372,619        1,430,931
                                                                                       ----------       ----------
                                                                                       $3,105,943       $3,052,243
                                                                                       ==========       ==========

                           CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
   Common stockholder's equity-
     Common stock, par value $20 per share, authorized 5,400,000 shares,
       5,290,596 shares outstanding...............................................     $  105,812       $  105,812
     Other paid-in capital........................................................      1,215,667        1,215,667
     Accumulated other comprehensive loss.........................................        (42,180)         (42,185)
     Retained earnings............................................................         23,697           18,038
                                                                                       ----------       ----------
       Total common stockholder's equity..........................................      1,302,996        1,297,332
   Long-term debt and other long-term obligations.................................        588,255          438,764
                                                                                       ----------       ----------
                                                                                        1,891,251        1,736,096
                                                                                       ----------       ----------
CURRENT LIABILITIES:
   Currently payable long-term debt ..............................................        125,605          125,762
   Short-term borrowings-
     Associated companies.........................................................         17,185           78,510
   Accounts payable-
     Associated companies.........................................................         56,391           55,831
     Other........................................................................         28,893           40,192
   Accrued  taxes.................................................................          2,222            8,705
   Accrued interest...............................................................         15,330           12,694
   Other..........................................................................         25,068           21,764
                                                                                       ----------       ----------
                                                                                          270,694          343,458
                                                                                       ----------       ----------
NONCURRENT LIABILITIES:
   Accumulated deferred income taxes..............................................          7,717               --
   Accumulated deferred investment tax credits....................................          9,691            9,936
   Asset retirement obligation....................................................        106,631          105,089
   Nuclear fuel disposal costs....................................................         19,010           18,968
   Power purchase contract loss liability.........................................        629,965          670,482
   Retirement benefits............................................................        147,882          145,081
   Other..........................................................................         23,102           23,133
                                                                                       ----------       ----------
                                                                                          943,998          972,689
                                                                                       ----------       ----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 3)................................
                                                                                       ----------       ----------
                                                                                       $3,105,943       $3,052,243
                                                                                       ==========       ==========

<FN>
The preceding Notes to Consolidated Financial Statements as they relate to the Pennsylvania Electric Company are
an integral part of these balance sheets.
</FN>

                                                         129

</TABLE>

<PAGE>

<TABLE>

                                           PENNSYLVANIA ELECTRIC COMPANY

                                       CONSOLIDATED STATEMENTS OF CASH FLOWS
                                                    (Unaudited)

<CAPTION>
                                                                                        Three Months Ended
                                                                                              March 31,
                                                                                    ---------------------------
                                                                                      2004               2003
                                                                                    ---------          --------
                                                                                            (In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
<S>                                                                               <C>                <C>
Net income ..................................................................     $    5,659         $    5,290
   Adjustments to reconcile net income to net
     cash from operating activities-
       Provision for depreciation and amortization...........................         25,089             25,337
       Deferred costs recoverable as regulatory assets.......................        (17,993)           (11,656)
       Deferred income taxes, net............................................         25,487            (41,640)
       Investment tax credits, net...........................................           (245)              (247)
       Accrued retirement benefit obligations................................          2,802                 --
       Accrued compensation, net.............................................          2,255                 62
       Cumulative effect of accounting change (Note 2).......................             --             (1,873)
       Receivables...........................................................        (12,129)             5,440
       Accounts payable......................................................        (10,738)             8,666
       Accrued taxes.........................................................         (6,483)            27,284
       Accrued interest......................................................          2,636              5,679
       Prepayments and other current assets..................................        (47,054)           (34,778)
       Other.................................................................          3,654             (7,152)
                                                                                    --------           --------
         Net cash used for operating activities..............................        (27,060)           (19,588)
                                                                                    --------           --------

CASH FLOWS FROM FINANCING ACTIVITIES:
   New Financing-
     Long-term debt..........................................................        150,000                 --
   Redemptions and Repayments-
     Long-term debt..........................................................           (104)                --
     Short-term borrowings, net..............................................        (61,326)           (90,427)
                                                                                    --------           ---------
   Net cash provided from (used for) financing activities....................         88,570            (90,427)
                                                                                    --------           ---------

CASH FLOWS FROM INVESTING ACTIVITIES:
   Property additions........................................................        (11,194)            (6,312)
   Non-utility generation trusts withdrawals (contributions).................        (50,614)           106,327
   Loans to associated companies.............................................            (71)                --
   Other, net................................................................            369                 --
                                                                                    --------           --------
         Net cash provided from (used for) investing activities..............        (61,510)           100,015
                                                                                    ---------          --------

Net change in cash and cash equivalents......................................             --            (10,000)
Cash and cash equivalents at beginning of period ............................             36             10,310
                                                                                    --------           --------
Cash and cash equivalents at end of period...................................       $     36           $    310
                                                                                    ========           ========


<FN>
The preceding Notes to Consolidated Financial Statements as they relate to the Pennsylvania Electric Company are
an integral part of these statements.
</FN>

                                                         130

</TABLE>

<PAGE>


                        REPORT OF INDEPENDENT ACCOUNTANTS


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,  2004,  and the related
consolidated  statements  of income and cash  flows for each of the  three-month
periods ended March 31, 2004 and 2003.  These interim  financial  statements are
the responsibility of the Company's management.

We conducted our review in accordance with standards established by the American
Institute  of  Certified  Public  Accountants.  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 generally
accepted  auditing  standards,  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 auditing  standards  generally accepted
in the  United  States  of  America,  the  consolidated  balance  sheet  and the
consolidated  statement  of  capitalization  as of December  31,  2003,  and the
related  consolidated   statements  of  income,   common  stockholder's  equity,
preferred  stock,  cash flows and taxes for the year then  ended (not  presented
herein),  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 1(E) 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 8 to
those consolidated  financial  statements) dated February 25, 2004, we expressed
an  unqualified  opinion  on those  consolidated  financial  statements.  In our
opinion,  the information set forth in the accompanying  condensed  consolidated
balance sheet as of December 31, 2003, 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 7, 2004

                                      131

<PAGE>


                          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 provides  regulated  transmission  and distribution  services in western
Pennsylvania.  Pennsylvania  customers  are  able to  choose  their  electricity
suppliers as a result of legislation  which  restructured  the electric  utility
industry.   Penelec's   regulatory  plan  required   unbundling  the  price  for
electricity into its component  elements - including  generation,  transmission,
distribution and transition charges. Penelec continues to deliver power to homes
and  businesses  through its  existing  distribution  system and  maintains  PLR
obligations to customers who elect to retain Penelec as their power supplier.

Results from Operations
-----------------------

          Net income in the first  quarter of 2004  increased  to $5.7  million,
compared to $5.3 million in the first  quarter of 2003.  Net income in the first
quarter of 2003 included an after-tax credit of $1.1 million from the cumulative
effect of an  accounting  change due to the adoption of SFAS 143.  Income before
the  cumulative  effect  was $5.7  million  in the first  three  months of 2004,
compared to $4.2 million for the same period of 2003. The increase in net income
was the  result of  higher  operating  revenues  and  lower  operating  costs --
partially offset by a lower level of deferred interest costs.

          Operating  revenues  increased  by $1.6  million  or 0.6% in the first
quarter of 2004  compared  with the same  period in 2003.  The  higher  revenues
resulted from increased  distribution revenues offset by lower retail generation
revenues.  Revenues  from  electricity  throughput  increased by $9 million as a
result of higher  unit prices  which were  partially  offset by  slightly  lower
distribution  deliveries compared to the prior year. Penelec's retail generation
kilowatt-hour  sales increased 1.5% reflecting higher residential and commercial
sales of 3.5% and 0.5%, respectively.  Retail generation sales revenue decreased
$5.3 million  reflecting  lower unit prices,  which offset the generation  sales
increase  as  more  customers  returned  from  alternative  suppliers.  Although
wholesale  kilowatt-hour  sales increased 121.3%, the volume was minimal for the
first quarters of 2004 and 2003 and revenues increased only slightly.

          Changes in electric  generation sales and  distribution  deliveries in
the first quarter of 2004 from the first  quarter of 2003 are  summarized in the
following table:

                  Changes in  Kilowatt-Hour Sales
                  ---------------------------------------------------
                  Increase (Decrease)
                    Electric Generation:
                      Retail................................     1.5%
                      Wholesale.............................   121.3%
                    -------------------------------------------------
                    Total Electric Generation Sales.........     1.9%
                    =================================================
                    Distribution Deliveries:
                      Residential...........................     3.4%
                      Commercial............................     0.5%
                      Industrial............................    (4.5)%
                    --------------------------------------------------
                    Total Distribution Deliveries...........    (0.4)%
                    ==================================================

                                      132

<PAGE>



       Operating Expenses and Taxes

          Total operating expenses and taxes decreased $1 million or 0.5% in the
first  quarter of 2004 from the first  quarter of 2003,  primarily  due to lower
other operating costs  partially  offset by increased  purchased power costs and
general taxes.  The following table presents changes during the first quarter of
2004 from the same period in 2003 for operating expenses and taxes.

          Operating Expenses and Taxes - Changes
          -----------------------------------------------------------------
           Increase (Decrease)                                 (In millions)
          Purchased power .................................       $  1
          Other operating costs............................         (3)
          -----------------------------------------------------------------
            Total operation and maintenance expenses.......         (2)

          Provision for depreciation and amortization......         --
          General taxes....................................          1
          Income taxes.....................................         --
          -----------------------------------------------------------------
            Total operating expenses and taxes.............       $ (1)
          =================================================================

          Lower other  operating  costs in the first  quarter of 2004,  compared
with the same quarter of 2003, were due to reduced  postretirement  benefit plan
expenses,  lower  uncollectible  customer  accounts and  transmission  expenses.
Purchased  power costs  increased due primarily to increased PLR purchases  from
FES,  partially  offset by reduced  two-party  energy  purchases.  General taxes
increased due to higher  payroll taxes from the transfer of employees to Penelec
from GPUS.

       Net Interest Charges

          Net interest charges increased by $1.5 million in the first quarter of
2004  compared  with the first  quarter  of 2003,  reflecting  a lower  level of
deferred interest costs.

       Cumulative Effect of Accounting Change

          Upon  adoption  of SFAS 143 in the  first  quarter  of  2003,  Penelec
recorded  an  after-tax  credit to net income of $1.1  million.  The  cumulative
adjustment for unrecognized  depreciation,  accretion offset by the reduction in
the existing  decommissioning  liabilities  and ceasing the accounting  practice
depreciating  non-regulated  generation assets using a cost of removal component
was an $1.9 million increase to income, or $1.1 million net of income taxes.

Capital Resources and Liquidity
-------------------------------

          Penelec's   cash   requirements   in  2004  for  operating   expenses,
construction  expenditures  and scheduled debt maturities are expected to be met
without increasing its net debt and preferred stock  outstanding.  Over the next
two years,  Penelec expects to meet its contractual  obligations  with cash from
operations.  Thereafter,  Penelec  expects  to use a  combination  of cash  from
operations and funds from the capital markets.

       Changes in Cash Position

          As of March 31, 2004 and  December  31,  2003,  Penelec had $36,000 of
cash and cash equivalents.

       Cash Flows From Operating Activities

          Cash  used by  operating  activities  in the  first  quarter  of 2004,
compared with the first quarter of 2003 were as follows:

          Operating Cash Flows                     2004          2003
          -------------------------------------------------------------
                                                      (In millions)

          Cash earnings (1)....................    $  43       $  (25)
          Working capital and other............      (70)           5
          -------------------------------------------------------------

          Total................................     $(27)      $  (20)
          =============================================================

          (1)  Includes net income, depreciation and amortization, deferred
               costs  recoverable  as regulatory  assets,  deferred  income
               taxes, investment tax credits and pension changes.


          Net cash used for operating activities increased to $27 million in the
first quarter of 2004 from $20 million in the same period of 2003. In 2004,  the
increase was due to the increase of working capital requirements (primarily from
changes in  accounts  receivable  and  payable)  offset by an  increase  in cash
earnings from higher deferred income taxes.

       Cash Flows From Financing Activities

          Net cash  provided  from  financing  activities  of $89 million in the
first quarter of 2004 compared to net cash used for financing  activities of $90
million in the first quarter of 2003,  represents  the issuance in March 2004 of
$150  million of long-term  debt  partially  offset by a decrease in  short-term
borrowings. The proceeds from the $150 million issuance were used to redeem $125

                                      133

<PAGE>

million  principal  amount of senior  notes that matured on April 1, 2004 and to
repay short-term borrowings.

          As  of  March  31,  2004,   Penelec  had  $17  million  of  short-term
indebtedness,  compared  to $79  million at the end of 2003.  Penelec may borrow
from its affiliates on a short-term basis. Penelec will not issue first mortgage
bonds other than as collateral for senior notes, since its senior note indenture
prohibits  (subject  to certain  exceptions)  it from  issuing any debt which is
senior to the senior notes. As of March 31, 2004,  Penelec had the capability to
issue $6.5 million of  additional  senior notes based upon first  mortgage  bond
collateral. Penelec had no restrictions on the issuance of preferred stock.

          In March 2004,  Penelec  completed  an  on-balance  sheet,  receivable
financing transaction which allows it to borrow up to $75 million. The borrowing
rate is based on bank  commercial  paper  rates.  Penelec is  required to pay an
annual  facility  fee of 0.30% on the entire  finance  limit.  The  facility was
undrawn as of March 31, 2004. This facility matures on March 29, 2005.

          Penelec'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 of its securities is stable.

          On February 6, 2004, Moody's  downgraded  FirstEnergy senior unsecured
debt to Baa3 from Baa2 and downgraded  the senior secured debt of JCP&L,  Met-Ed
and Penelec to Baa1 from A2. Moody's also  downgraded the preferred stock rating
of JCP&L to Ba1 from Baa2 and the  senior  unsecured  rating of  Penelec to Baa2
from A2. The ratings of OE, CEI, TE and Penn were  confirmed.  Moody's said that
the  lower  ratings  were  prompted  by:  "1) high  consolidated  leverage  with
significant  holding company debt, 2) a degree of regulatory  uncertainty in the
service  territories in which the company  operates,  3) risks  associated  with
investigations of the causes of the August 2003 blackout, and related securities
litigation,  and 4) a  narrowing  of  the  ratings  range  for  the  FirstEnergy
operating utilities,  given the degree to which FirstEnergy increasingly manages
the utilities as a single system and the significant financial interrelationship
among the subsidiaries."

          On March 9, 2004, S&P stated that the NRC's permission for FirstEnergy
to restart the Davis-Besse nuclear plant was positive for credit quality because
it would positively affect cash flow by eliminating  replacement power costs and
"demonstrating   management's  ability  to  overcome  operational   challenges."
However, S&P did not change  FirstEnergy's  ratings or outlook because it stated
that financial performance still "significantly lags expectations and management
faces other operational hurdles."

       Cash Flows From Investing Activities

          Net cash used for investing  activities  were $62 million in the first
quarter  of  2004,  compared  to net cash  provided  from  investing  activities
totaling  $100  million  in the  first  quarter  of 2003.  The net cash used for
investing  activities  resulted from a refunding payment of $51 million to a NUG
trust fund and  increased  property  additions in 2004.  In the first quarter of
2003, net cash provided from investing  activities resulted from $106 million of
withdrawals  from the NUG trust fund,  partially  offset by property  additions.
Expenditures for property additions  primarily support Penelec's energy delivery
operations.

          During  the  remaining  quarters  of 2004,  capital  requirements  for
property additions are expected to be about $54 million.  Penelec has additional
requirements of  approximately  $125 million for maturing  long-term debt during
the remainder of 2004. These cash requirements (excluding debt refinancings) are
expected to be satisfied from internal cash and short-term credit arrangements.

Off-Balance Sheet Arrangements
------------------------------

          As  of  March  31,  2004,  Penelec's  off-balance  sheet  arrangements
included  certain  statutory  business  trusts created by Penelec to issue trust
preferred  securities  of $92 million.  These trusts were  included in Penelec's
financial  statements  prior to the adoption of FIN 46R,  but have  subsequently
been  deconsolidated  under FIN 46R (see Note 2 - Variable  Interest  Entities).
This deconsolidation has not resulted in any change in outstanding debt.

Market Risk Information
-----------------------

          Penelec  uses various  market risk  sensitive  instruments,  including
derivative  contracts,  primarily  to  manage  the risk of  price  fluctuations.
FirstEnergy's Risk Policy Committee,  comprised of executive officers, exercises
an independent risk oversight  function to ensure compliance with corporate risk
management policies and prudent risk management practices.

                                      134

<PAGE>

       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 future  contracts.  The  derivatives are used for hedging
purposes. Most of Penelec'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 2004 is summarized in the following table:

<TABLE>
Increase (Decrease) in the Fair Value
of Commodity Derivative Contracts
<CAPTION>
                                                                Non-Hedge     Hedge      Total
-----------------------------------------------------------------------------------------------
                                                                                     (In millions)
Change in the Fair Value of Commodity Derivative Contracts
<S>                                                                 <C>        <C>        <C>
Outstanding net asset as of January 1, 2004...................      $15        $ --       $15
New contract value when entered...............................       --          --        --
Additions/change in value of existing contracts...............       --          --        --
Change in techniques/assumptions..............................       --          --        --
Settled contracts.............................................       --          --        --
-----------------------------------------------------------------------------------------------
Net Assets - Derivatives Contracts as of March 31, 2004 (1)...      $15        $ --       $15
===============================================================================================
</TABLE>

(1) Includes $14 million in non-hedge  commodity  derivative  contracts which
    are offset by a regulatory liability.


Derivatives included on the Consolidated Balance Sheet as of March 31, 2004:


                                                    Non-Hedge    Hedge    Total
          ---------------------------------------------------------------------
                                                             (In millions)
          Current-
                Other Assets......................    $--       $ --      $--

          Non-Current-
                Other Deferred Charges............     15         --       15
          ---------------------------------------------------------------------

                Net assets........................    $15       $ --      $15
          =====================================================================

          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.  Sources  of  information  for  the  valuation  of
derivative contracts by year are summarized in the following table:

<TABLE>

<CAPTION>
Source of Information
- Fair Value by Contract Year           2004       2005       2006    2007    Thereafter   Total
-------------------------------------------------------------------------------------------------
                                                            (In millions)
<S>                                      <C>        <C>        <C>     <C>        <C>       <C>
Prices based on external sources(1)...   $ 2        $ 3        $--     $ --       $--       $ 5
Prices based on model.................    --         --          2        2         6        10
-------------------------------------------------------------------------------------------------

    Total(2)..........................   $ 2        $ 3        $ 2      $ 2       $ 6       $15
=================================================================================================
</TABLE>

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

          Penelec 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, 2004.

       Equity Price Risk

          Included in Penelec's  nuclear  decommissioning  trust investments are
marketable equity securities  carried at their market value of approximately $55
million  and  $54  million  as  of  March  31,  2004  and   December  31,  2003,
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, 2004.

                                      135

<PAGE>

Outlook
-------

          Beginning  in 1999,  all of  Penelec's  customers  were able to select
alternative  energy  suppliers.  Penelec continues to deliver power to homes and
businesses through its existing  distribution  system,  which remains regulated.
The PPUC authorized  Penelec's rate restructuring  plan,  establishing  separate
charges for transmission,  distribution,  generation and stranded cost recovery,
which is  recovered  through a CTC.  Customers  electing to obtain power from an
alternative  supplier have their bills reduced based on the regulated generation
component,  and the customers  receive a generation  charge from the alternative
supplier.  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, which is referred to as its PLR obligation.

          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. All of Penelec's
regulatory  assets are expected to continue to be recovered under the provisions
of the regulatory plan as discussed below.  Penelec's  regulatory assets totaled
$459  million  and $497  million as of March 31,  2004 and  December  31,  2003,
respectively.

       Regulatory Matters

          In June 2001, the PPUC approved the Settlement Stipulation with all of
the major parties in the combined merger and rate proceedings which approved the
FirstEnergy/GPU merger and provided PLR deferred accounting treatment for energy
costs, permitting Penelec to defer, for future recovery,  energy costs in excess
of amounts  reflected in its capped  generation rates  retroactive to January 1,
2001.  This PLR deferral  accounting  procedure was later reversed in a February
2002 Commonwealth  Court of Pennsylvania  decision.  The court decision affirmed
the PPUC decision  regarding  approval of the merger,  remanding the decision to
the PPUC only with respect to the issue of merger savings. Penelec established a
$111.1 million  reserve in 2002 for its PLR deferred energy costs incurred prior
to its  acquisition by FirstEnergy,  reflecting the potential  adverse impact of
the then  pending  Pennsylvania  Supreme  Court  decision  whether to review the
Commonwealth Court decision.  The reserve increased goodwill by an aggregate net
of tax amount of $65.0 million.

          On April 2,  2003,  the PPUC  remanded  the issue  relating  to merger
savings to the ALJ for hearings,  directed  Penelec to file a position  paper on
the effect of the  Commonwealth  Court order on the Settlement  Stipulation  and
allowed other parties to file responses to the position  paper.  Penelec filed a
letter with the ALJ on June 11, 2003,  voiding the  Stipulation  in its entirety
and reinstating  Penelec's  restructuring  settlement previously approved by the
PPUC.

          On October  2,  2003,  the PPUC  issued an order  concluding  that the
Commonwealth Court reversed the PPUC's June 20, 2001 order in its entirety.  The
PPUC directed Penelec to file tariffs within thirty days of the order to reflect
the CTC rates and  shopping  credits  that were in effect  prior to the June 21,
2001 order to be  effective  upon one day's  notice.  In response to that order,
Penelec filed these  supplements to its tariffs to become effective  October 24,
2003.

          On  October  8,  2003,  Penelec  filed a  petition  for  clarification
relating to the October 2, 2003 order on two issues:  to establish June 30, 2004
as the date to fully  refund the NUG trust fund and to clarify  that the ordered
accounting  treatment regarding the CTC rate/shopping  credit swap should follow
the  ratemaking,  and that the  PPUC's  findings  would not impair its rights to
recover all of its stranded costs. On October 9, 2003,  ARIPPA (an intervenor in
the proceedings)  petitioned the PPUC to direct Penelec to reinstate  accounting
for the CTC  rate/shopping  credit swap retroactive to January 1, 2002.  Several
other  parties  also filed  petitions.  On October 16,  2003,  the PPUC issued a
reconsideration  order  granting the date requested by Penelec for the NUG trust
fund refund and,  denying  Penelec's other  clarification  requests and granting
ARIPPA's  petition with respect to the retroactive  accounting  treatment of the
changes to the CTC rate/shopping credit swap. On October 22, 2003, Penelec filed
an  Objection  with the  Commonwealth  Court  asking that the Court  reverse the
PPUC's finding that requires Penelec to treat the stipulated CTC rates that were
in effect from January 1, 2002 on a retroactive basis.

          On October 27,  2003,  one  Commonwealth  Court judge  issued an Order
denying  Penelec's  objection without  explanation.  Due to the vagueness of the
Order, Penelec, on October 31, 2003, filed an Application for Clarification with
the judge.  Concurrent  with this  filing,  Penelec,  in order to  preserve  its
rights, also filed with the Commonwealth Court both a Petition for Review of the
PPUC's October 16 and October 22 Orders,  and an application for reargument,  if
the judge, in his clarification  order,  indicates that Penelec's  objection was
intended to be denied on the merits. In addition to these findings,  Penelec, in
compliance with the PPUC's Orders,  filed revised PPUC quarterly reports for the
twelve months ended  December 31, 2001 and 2002,  and for the first two quarters
of 2003,  reflecting  balances  consistent  with the  PPUC's  findings  in their
Orders.

                                      136

<PAGE>

          Effective  September 1, 2002,  Penelec agreed to purchase a portion of
its PLR requirements from FES through a wholesale power sale agreement.  The PLR
sale will be 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 assumed 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. FES has
hedged most of  Penelec's  unfilled  PLR on-peak  obligation  through 2004 and a
portion of 2005,  the period during which  deferred  accounting  was  previously
allowed  under the PPUC's order.  Penelec is  authorized  to continue  deferring
differences between NUG contract costs and current market prices.

          In late 2003,  the PPUC  issued a  Tentative  Order  implementing  new
reliability  benchmarks  and  standards.  In  connection  therewith,   the  PPUC
commenced a  rulemaking  procedure  to amend the  Electric  Service  Reliability
Regulations to implement these new benchmarks,  and create additional  reporting
on  reliability.  Although  neither  the  Tentative  Order  nor the  Reliability
Rulemaking has been finalized,  the PPUC ordered all  Pennsylvania  utilities to
begin filing quarterly  reports on November 1, 2003. The comment period for both
the Tentative  Order and the Proposed  Rulemaking  Order has closed.  Penelec is
currently  awaiting the PPUC to issue a final order in both  matters.  The order
will  determine  (1) the standards  and  benchmarks to be utilized,  and (2) the
details required in the quarterly and annual reports.

          On January 16,  2004,  the PPUC  initiated a formal  investigation  of
whether Penelec's "service reliability performance deteriorated to a point below
the  level of  service  reliability  that  existed  prior to  restructuring"  in
Pennsylvania.  Discovery has commenced in the proceeding and Penelec's testimony
is due May 14,  2004.  Hearings  are  scheduled  to begin August 3, 2004 in this
investigation  and the ALJ has been directed to issue a Recommended  Decision by
September  30,  2004,  in order to allow the PPUC time to issue a Final Order by
year end of 2004.  Penelec is unable to predict the outcome of the investigation
or the impact of the PPUC order.

       Environmental Matters

          Penelec  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 be held  liable  on a joint and  several  basis.  Therefore,  environmental
liabilities   that  are  considered   probable  have  been   recognized  on  the
Consolidated  Balance Sheets,  based on estimates of the total costs of cleanup,
Penelec's proportionate  responsibility for such costs and the financial ability
of  other  nonaffiliated  entities  to  pay.  Penelec  has  accrued  liabilities
aggregating  approximately  $30,000  as  of  March  31,  2004.  Penelec  accrues
environmental  liabilities only when it can conclude that it is probable that an
obligation for such costs exists and can reasonably determine the amount of such
costs.   Unasserted   claims  are  reflected  in  Penelec's   determination   of
environmental  liabilities  and are  accrued  in the  period  that they are both
probable and reasonably estimable.

       Power Outage

          On August  14,  2003,  various  states  and parts of  southern  Canada
experienced a widespread power outage.  That outage affected  approximately  1.4
million  customers in  FirstEnergy's  service area.  On April 5, 2004,  the U.S.
-Canada Power System Outage Task Force released its final report on this outage.
The final report supercedes the interim report that had been issued in November,
2003. In the final report,  the Task Force concluded,  among other things,  that
the problems  leading to the outage began in  FirstEnergy's  Ohio service  area.
Specifically,   the  final  report  concludes,  among  other  things,  that  the
initiation of the August 14th power outage resulted from the coincidence on that
afternoon of several events,  including,  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 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 14th power outage and that it does not
adequately  address the  underlying  causes of the outage.  FirstEnergy  remains
convinced  that the outage  cannot be explained  by events on any one  utility's
system. The final report contains 46 "recommendations to prevent or minimize the
scope of future blackouts."  Forty-five of those recommendations relate to broad
industry  or policy  matters  while one  relates  to  activities  the Task Force
recommends be undertaken by FirstEnergy,  MISO,  PJM, and ECAR.  FirstEnergy has
undertaken  several  initiatives,  some prior to and some since the August  14th
power outage,  to enhance  reliability which are consistent with these and other
recommendations  and believes it will complete  those relating to summer 2004 by
June 30 (see  Reliability  Initiatives  below).  As  many of  these  initiatives
already were in process and budgeted in 2004,  FirstEnergy does not believe that
any  incremental  expenses  associated with  additional  initiatives  undertaken
during 2004 will have a material effect on its operations or financial  results.

                                      137

<PAGE>

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.

       Reliability Initiatives

          On  October  15,  2003,  NERC  issued a Near  Term  Action  Plan  that
contained  recommendations  for all control areas and  reliability  coordinators
with  respect  to  enhancing  system   reliability.   Approximately  20  of  the
recommendations  were directed at the FirstEnergy  companies and broadly focused
on  initiatives  that are  recommended  for  completion  by summer  2004.  These
initiatives  principally  relate to  changes in voltage  criteria  and  reactive
resources  management;  operational  preparedness  and action  plans;  emergency
response   capabilities;   and,  preparedness  and  operating  center  training.
FirstEnergy   presented  a  detailed   compliance  plan  to  NERC,   which  NERC
subsequently  endorsed on May 7, 2004, and the various  initiatives are expected
to be completed no later than June 30, 2004.

          On February 26-27, 2004, certain FirstEnergy companies participated in
a NERC Control Area Readiness Audit. This audit, part of an announced program by
NERC to review  control area  operations  throughout  much of the United  States
during 2004, is an  independent  review to identify areas for  improvement.  The
final  audit  report was  completed  on April 30,  2004.  The report  identified
positive  observations  and included  various  recommendations  for improvement.
FirstEnergy  is currently  reviewing the audit results and  recommendations  and
expects to  implement  those  relating to summer  2004 by June 30.  Based on its
review thus far, FirstEnergy believes that none of the recommendations  identify
a  need  for  any  incremental  material  investment  or  upgrades  to  existing
equipment.  FirstEnergy notes, however, that NERC 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.

          On March 1, 2004, certain  FirstEnergy  companies filed, in accordance
with a November 25, 2003 order from the PUCO, their plan for addressing  certain
issues  identified  by the PUCO from the U.S. - Canada Power System  Outage Task
Force  interim  report.  In  particular,   the  filing  addressed   upgrades  to
FirstEnergy's  control room computer  hardware and software and  enhancements to
the  training of control  room  operators.  The PUCO will review the plan before
determining the next steps, if any, in the proceeding.

          On April 22,  2004,  FirstEnergy  filed  with FERC the  results of the
FERC-ordered independent study of part of Ohio's power grid. The study examined,
among other things,  the reliability of the transmission grid in critical points
in  the  Northern  Ohio  area  and  the  need,   if  any,  for  reactive   power
reinforcements  during summer 2004 and 2005.  FirstEnergy is currently reviewing
the  results  of that  study and  expects  to  complete  the  implementation  of
recommendations  relating to 2004 by this summer.  Based on its review thus far,
FirstEnergy  believes that the study does not recommend any incremental material
investment or 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.

          With respect to each of the  foregoing  initiatives,  FirstEnergy  has
requested and NERC has agreed to provide, a technical assistance team of experts
to provide ongoing guidance and assistance in implementing and confirming timely
and successful completion.

       Legal Matters

          Various lawsuits,  claims and proceedings  related to Penelec's normal
business  operations are pending  against it, the most  significant of which are
described above.

Critical Accounting Policies

          Penelec prepares its consolidated  financial  statements in accordance
with GAAP.  Application  of these  principles  often  requires a high  degree of
judgment,  estimates  and  assumptions  that affect  financial  results.  All of
Penelec's assets are subject to their own specific risks and  uncertainties  and
are regularly reviewed for impairment.  Assets related to the application of the
policies   discussed   below  are  similarly   reviewed  with  their  risks  and
uncertainties  reflecting  these specific  factors.  Penelec's more  significant
accounting policies are described below.

       Regulatory Accounting

          Penelec is subject to  regulation  that sets the prices  (rates) it is
permitted to charge its customers  based on costs that the  regulatory  agencies
determine  Penelec is  permitted  to recover.  At times,  regulators  permit the
future  recovery  through  rates of costs  that  would be  currently  charged to
expense by an  unregulated  company.  This  rate-making  process  results in the
recording of regulatory  assets based on anticipated  future cash inflows.  As a
result of the changing  regulatory  framework  in  Pennsylvania,  a  significant
amount of  regulatory  assets have been  recorded - $459 million as of March 31,
2004.   Penelec   regularly  reviews  these  assets  to  assess  their  ultimate

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<PAGE>

recoverability  within  the  approved  regulatory  guidelines.  Impairment  risk
associated  with  these  assets  relates  to  potentially  adverse  legislative,
judicial or regulatory actions in the future.

       Derivative Accounting

          Determination  of appropriate  accounting for derivative  transactions
requires the involvement of management representing operations, finance and risk
assessment.  In order to determine the  appropriate  accounting  for  derivative
transactions,  the  provisions of the contract need to be carefully  assessed in
accordance  with  the  authoritative   accounting  literature  and  management's
intended use of the derivative.  New authoritative  guidance  continues to shape
the  application  of  derivative  accounting.   Management's   expectations  and
intentions  are key factors in  determining  the  appropriate  accounting  for a
derivative  transaction and, as a result,  such  expectations and intentions are
documented. Derivative contracts that are determined to fall within the scope of
SFAS 133, as amended, must be recorded at their fair value. Active market prices
are not always  available  to  determine  the fair value of the later years of a
contract,  requiring  that various  assumptions  and  estimates be used in their
valuation. Penelec continually monitors its derivative contracts to determine if
its  activities,  expectations,  intentions,  assumptions  and estimates  remain
valid.  As  part  of  its  normal  operations,  Penelec  enters  into  commodity
contracts,  as well as  interest  rate  swaps,  which  increase  the  impact  of
derivative accounting judgments.

       Revenue Recognition

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

       Pension and Other Postretirement Benefits Accounting

          FirstEnergy's  reported  costs of providing  non-contributory  defined
pension benefits and  postemployment  benefits other than pensions are dependent
upon  numerous  factors  resulting  from  actual  plan  experience  and  certain
assumptions.

          Pension  and  OPEB  costs  are   affected  by  employee   demographics
(including  age,  compensation  levels,  and employment  periods),  the level of
contributions  FirstEnergy makes to the plans, and earnings on plan assets. Such
factors may be further affected by business  combinations (such as FirstEnergy's
merger with GPU in November 2001),  which impacts  employee  demographics,  plan
experience  and other  factors.  Pension  and OPEB  costs are also  affected  by
changes  to key  assumptions,  including  anticipated  rates of  return  on plan
assets,  the discount rates and health care trend rates used in determining  the
projected benefit obligations for pension and OPEB costs.

          In accordance  with SFAS 87 and SFAS 106,  changes in pension and OPEB
obligations  associated with these factors may not be immediately  recognized as
costs on the income statement, but generally are recognized in future years over
the remaining average service period of plan participants.  SFAS 87 and SFAS 106
delay  recognition  of changes due to the  long-term  nature of pension and OPEB
obligations and the varying market  conditions likely to occur over long periods
of time. As such, significant portions of pension and OPEB costs recorded in any
period  may not  reflect  the actual  level of cash  benefits  provided  to plan
participants and are significantly influenced by assumptions about future market
conditions and plan participants' experience.

          In selecting an assumed discount rate, FirstEnergy considers currently
available rates of return on high-quality fixed income  investments  expected to
be   available   during  the  period  to  maturity  of  the  pension  and  other
postretirement  benefit  obligations.  Due to recent  declines in corporate bond
yields and interest rates in general,  FirstEnergy  reduced the assumed discount
rate as of December 31, 2003 to 6.25% from 6.75% used as of December 31, 2002.

          FirstEnergy's  assumed rate of return on pension plan assets considers
historical  market  returns and economic  forecasts for the types of investments
held by its pension trusts.  In 2003 and 2002, plan assets actually earned 24.0%
and (11.3)%,  respectively.  FirstEnergy's  pension  costs in 2003 and the first
quarter  of 2004 were  computed  assuming  a 9.0% rate of return on plan  assets
based upon  projections  of future  returns  and its  pension  trust  investment
allocation of approximately 70% equities, 27% bonds, 2% real estate and 1% cash.

          Based on pension  assumptions  and pension  plan assets as of December
31, 2003,  FirstEnergy  will not be required to fund its pension  plans in 2004.
However,  health care cost trends have  significantly  increased and will affect
future  OPEB  costs.  The  2004  and  2003  composite  health  care  trend  rate
assumptions are approximately 10%-12% gradually decreasing to 5% in later years.

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<PAGE>

In determining  its trend rate  assumptions,  FirstEnergy  included the specific
provisions of its health care plans, the  demographics and utilization  rates of
plan participants,  actual cost increases  experienced in its health care plans,
and projections of future medical trend rates.

       Long-Lived Assets

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

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

       Nuclear Decommissioning

          In accordance with SFAS 143, Penelec  recognizes an ARO for the future
decommissioning  of TMI-2. The ARO liability  represents an estimate of the fair
value of Penelec's current obligation related to nuclear decommissioning. A fair
value measurement  inherently  involves  uncertainty in the amount and timing of
settlement  of the  liability.  Penelec used an expected  cash flow approach (as
discussed  in FASB  Concepts  Statement  No. 7 to measure  the fair value of the
nuclear  decommissioning  ARO. This approach  applies  probability  weighting to
discounted future cash flow scenarios that reflect a range of possible outcomes.

       Goodwill

          In a business  combination,  the excess of the purchase price over the
estimated  fair  values  of the  assets  acquired  and  liabilities  assumed  is
recognized  as  goodwill.  Based on the guidance  provided by SFAS 142,  Penelec
evaluates  goodwill  for  impairment  at least  annually  and would make such an
evaluation  more  frequently  if  indicators  of  impairment  should  arise.  In
accordance with the accounting  standard,  if the fair value of a reporting unit
is less than its carrying value (including goodwill), the goodwill is tested for
impairment.  If impairment were to be indicated Penelec would recognize a loss -
calculated as the difference  between the implied fair value of its goodwill and
the carrying value of the goodwill. Penelec's annual review was completed in the
third quarter of 2003,  with no  impairment  indicated.  The  forecasts  used in
Penelec's evaluations of goodwill reflect operations consistent with its general
business  assumptions.  Unanticipated  changes in those assumptions could have a
significant  effect on Penelec's  future  evaluations of goodwill.  In the first
quarter of 2004, Penelec reduced goodwill by $4 million for interest received on
a pre-merger income tax refund.  As of March 31, 2004,  Penelec had $894 million
of goodwill.

New Accounting Standards and Interpretations

       FSP  106-1,  "Accounting  and  Disclosure  Requirements  Related  to  the
       Medicare Prescription Drug, Improvement and Modernization Act of 2003"

          Issued   January  12,  2004,   FSP  106-1   permits  a  sponsor  of  a
postretirement  health care plan that  provides a  prescription  drug benefit to
make a one-time  election to defer  accounting  for the effects of the  Medicare
Act.  FirstEnergy  elected to defer the effects of the  Medicare  Act due to the
lack of specific guidance.  Pursuant to FSP 106-1,  FirstEnergy began accounting
for the effects of the Medicare Act  effective  January 1, 2004 as a result of a
February  2, 2004 plan  amendment  that  required  remeasurement  of the  plan's
obligations.  See Note 2 for a discussion  of the effect of the federal  subsidy
and plan amendment on the consolidated financial statements.

       FIN 46 (revised  December  2003),  "Consolidation  of  Variable  Interest
       Entities"

          In  December  2003,  the  FASB  issued  a  revised  interpretation  of
Accounting  Research  Bulletin  No.  51,  "Consolidated  Financial  Statements",
referred  to as  FIN  46R,  which  requires  the  consolidation  of a VIE  by an
enterprise if that enterprise is determined to be the primary beneficiary of the
VIE.  As  required,  Penelec  adopted  FIN 46R for  interests  in VIEs  commonly
referred to as special-purpose  entities effective December 31, 2003 and for all
other types of entities  effective  March 31, 2004.  Adoption of FIN 46R did not
have a material impact on Penelec's  financial  statements for the quarter ended
March 31, 2004. See Note 2 for a discussion of Variable Interest Entities.

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<PAGE>

          For the quarter ended March 31, 2004, Penelec  evaluated,  among other
entities,  its power purchase agreements and determined that it is possible that
two NUG entities might be considered  variable  interest  entities.  Penelec has
requested but not received the information  necessary to determine whether these
entities are VIEs or whether Penelec is the primary beneficiary.  In most cases,
the requested  information was deemed to be competitive and proprietary data. As
such,  Penelec  applied the scope exception that exempts  enterprises  unable to
obtain the necessary information to evaluate entities under FIN 46R. The maximum
exposure to loss from these  entities  results  from  increases  in the variable
pricing component under the contract terms and cannot be determined  without the
requested  data. The cost of purchased  power from these entities was $7 million
in each of the  quarters  ended March 31, 2004 and 2003.  Penelec is required to
continue  to make  exhaustive  efforts to obtain the  necessary  information  in
future periods and is unable to determine the possible  impact of  consolidating
any such entity without this information.

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<PAGE>


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, 2004,  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.

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<PAGE>


PART II.  OTHER INFORMATION
---------------------------

Item 1.   Legal Proceedings
          -----------------

          Reference   is   made  to  Note   3,   Commitments,   Guarantees   and
Contingencies,  of the Notes to Consolidated  Financial  Statements contained in
Part I, Item 1 for a description of certain legal proceedings.

Item 6.   Exhibits and Reports on Form 8-K
          --------------------------------

 (a) Exhibits

          Exhibit
          Number
          ------

          Met-Ed
          ------

              12    Fixed charge ratios
              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.

          Penelec
          -------

          12  Fixed charge ratios
              15    Letter from independent accountants
              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 chie
                    financial  officer, pursuant to 18 U.S.C. Section 1350.

          JCP&L
          -----

              12    Fixed charge ratios
              31.2  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.

          FirstEnergy
          -----------

              10-40 Employment, severance and change in control agreement
                    between FirstEnergy Corp.
                    and A. J. Alexander, dated February 17, 2004.
              15    Letter from independent accountants
              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.

          OE and Penn
          -----------

              15    Letter from independent accountants
              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.

          CEI and 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.

                                      143

<PAGE>

          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.

(b)  Reports on Form 8-K

       FirstEnergy, CEI and TE
       -----------------------

          FirstEnergy,  CEI and TE each filed the following four reports on Form
8-K  since  December  31,  2003:  A  report  dated  January  13,  2004  reported
FirstEnergy  Chief  Executive  Officer H. Peter Burg passed away. A report dated
January 20, 2004 reported  Anthony J.  Alexander  elected as  FirstEnergy  Chief
Executive  Officer and George M. Smart  elected as  FirstEnergy  Chairman of the
Board of Directors.  A report dated  February 9, 2004 reported  Moody's  lowered
debt  ratings for  FirstEnergy  and  subsidiaries.  A report dated March 8, 2004
reported that FirstEnergy began Davis-Besse restart with NRC authorization.

       OE, Penn, JCP&L, Met-Ed and Penelec
       -----------------------------------

          OE, Penn,  JCP&L,  Met-Ed and Penelec each filed the  following  three
reports on Form 8-K since  December 31,  2003:  A report dated  January 13, 2004
reported FirstEnergy Chief Executive Officer H. Peter Burg passed away. A report
dated  January 20, 2004 reported  Anthony J.  Alexander  elected as  FirstEnergy
Chief Executive  Officer and George M. Smart elected as FirstEnergy  Chairman of
the Board of Directors. A report dated February 9, 2004 reported Moody's lowered
debt ratings for FirstEnergy and subsidiaries.

                                      144

<PAGE>

                                    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 10, 2004


                                                  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. Wagner
                                                  Vice President, Controller
                                                and Chief Accounting Officer

                                      145