SECURITIES AND EXCHANGE COMMISSION
                             Washington, D. C. 20549

                                   FORM 10-Q/A

                                 AMENDMENT NO. 1

                                   (Mark One)
           [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
                         SECURITIES EXCHANGE ACT OF 1934

                  For the quarterly period ended June 30, 2003

                                       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.
-----------     -----------------------------------        ------------------
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


<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
    ----    -----

          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 AUGUST 8, 2003
                -----                                      --------------------
     The Toledo Edison Company, $5 par value                   39,133,887

          This  Form  10-Q/A  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),  availability
and cost of capital,  inability  of the  Davis-Besse  Nuclear  Power  Station to
restart  (including  because  of  an  inability  to  obtain  a  favorable  final
determination  from  the  Nuclear  Regulatory  Commission)  in the fall of 2003,
inability to accomplish or realize  anticipated  benefits from strategic  goals,
further  investigation  into the causes of the August 14, 2003, power outage and
other similar factors.


<PAGE>


                                EXPLANATORY NOTE

We are filing this Amendment No. 1 to our Quarterly  Report on Form 10-Q for the
quarter ended June 30, 2003 (the  "Report") to correct  typographical  errors in
Item 2 -  MANAGEMENT'S  DISCUSSION  AND  ANALYSIS OF RESULTS OF  OPERATIONS  AND
FINANCIAL  CONDITION of the Report.  This  Amendment has no effect on previously
reported results of operations or financial position.

The  complete  amended and  restated  Item 2, which is included in its  entirety
below, reflects the following corrections:

Under the heading "RESULTS OF OPERATIONS":

     Under the subheading "Net Interest Charges":

          In the first  sentence,  the decrease in net interest  charges of $7.5
          million in the first half of 2003 should have read $8.2 million.


Under the heading "SIGNIFICANT ACCOUNTING POLICIES",

     Under the subheading "Regulatory Accounting":

          In the fifth sentence of the first paragraph,  total regulatory assets
          as of June 30, 2003 of $548.5 million should have read $537.3 million.


<PAGE>


                                TABLE OF CONTENTS


                                                                        Pages

Part I.       Financial Information

         The Toledo Edison Company

              Consolidated Statements of Income........................   *
              Consolidated Balance Sheets..............................   *
              Consolidated Statements of Cash Flows....................   *
              Report of Independent Auditors...........................   *
              Management's Discussion and Analysis of Results
                of Operations and Financial Condition..................  1-9

Part II.      Other Information


*    Indicates the items that have not been revised and are not included in this
     Form 10-Q/A. Reference is made to the original 10-Q for complete text of
     such items.


<PAGE>

           THE FOLLOWING ITEM HAS BEEN AMENDED IN THIS AMENDMENT NO.1:
                                     PART I
      ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
                             AND FINANCIAL CONDITION


                            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 portions of 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 wholesale
customers  under  previously  negotiated  contracts,  as well as 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

          As  further  discussed  in  Note  1  to  the  Consolidated   Financial
Statements, TE identified certain accounting matters that require restatement of
the consolidated  financial  statements for the year ended December 31, 2002 and
the three  months ended March 31, 2003.  The  revisions  reflect a change in the
method of amortizing  the costs  associated  with the Ohio  transition  plan and
recognition of above-market values of certain leased generation facilities.

       Transition Cost Amortization

          As discussed in Note 4 - Regulatory  Matters,  TE recovers  transition
costs,  including  regulatory assets,  through an approved transition plan filed
under Ohio's electric  utility  restructuring  legislation.  The plan, which was
approved in July 2000,  provides  for the recovery of costs from January 1, 2001
through a fixed number of kilowatt-hour  sales to all customers that continue to
receive regulated  transmission and distribution  service,  which is expected to
end in 2007 for TE.

          TE amortizes transition costs using the effective interest method. The
amortization  schedules  developed in applying this method were previously based
on total transition revenues, including revenues designed to recover costs which
have not yet been incurred or that were  recognized on the regulatory  financial
statements  (fair value purchase  accounting  adjustments).  TE has subsequently
revised  the  amortization  schedules  under the  effective  interest  method to
consider only revenues  relating to transition  regulatory  assets recognized on
the balance sheet. The  amortization  expense under the revised method (see Note
1) increased  by $17.6  million for the three months and $34 million for the six
months ended June 30, 2002.

       Above-Market Lease Costs

          In 1997,  FirstEnergy Corp. was formed through a merger between OE and
Centerior  Energy  Corp.  The  merger was  accounted  for as an  acquisition  of
Centerior,  the parent  company of TE,  under the purchase  accounting  rules of
Accounting  Principles  Board  (APB)  Opinion  No.  16. In  connection  with the
reassessment of the accounting for the transition plan,  FirstEnergy  reassessed
its accounting for the Centerior purchase and determined that above market lease
liabilities should have been recorded at the time of the merger. Accordingly, as
of 2002,  FirstEnergy recorded additional  adjustments  associated with the 1997
merger  between  OE  and  Centerior  to  reflect   certain  above  market  lease
liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant, for which TE
had previously entered into sale-leaseback arrangements. TE recorded an increase
in goodwill  related to the above  market  lease costs for Beaver  Valley Unit 2
since regulatory  accounting for nuclear generating assets had been discontinued
prior to the merger date and it was determined  that this  additional  liability
would have  increased  goodwill  at the date of the  merger.  The  corresponding
impact of the above market lease  liabilities for the Bruce Mansfield Plant were
recorded  as  regulatory  assets  because  regulatory  accounting  had not  been
discontinued at that time for the fossil generating assets and recovery of these
liabilities was provided for under the transition plan.

          The total above market  lease  obligation  of $111 million  associated
with Beaver Valley Unit 2 will be amortized through the end of the lease term in
2017.  The  additional  goodwill  has been  recorded on a net basis,  reflecting
amortization   that  would  have  been  recorded   through  2001  when  goodwill
amortization  ceased with the adoption of SFAS 142. The total above market lease
obligation of $298 million  associated  with the Bruce  Mansfield Plant is being
amortized  through the end of 2016.  Before the start of the transition  plan in
fiscal 2001, the regulatory  asset would have been amortized at the same rate as
the lease obligation.  Beginning in 2001, the remaining  unamortized  regulatory
asset would have been  included in TE's  amortization  schedule  for  regulatory
assets and amortized through the end of the recovery period - approximately 2007
for TE.

                                       1

<PAGE>


RESULTS OF OPERATIONS

          TE  experienced  a loss of $11.9 million on common stock in the second
quarter of 2003 or a decrease of $26.2 million from earnings of $14.3 million in
the second quarter of 2002.  Earnings on common stock in the first six months of
2003  increased  to $10.0  million  from $9.9 million in the first half of 2002.
Results in the first six months of 2003  included an after-tax  credit of $25.60
million from the cumulative  effect of an accounting  change due to the adoption
of SFAS 143, "Accounting for Asset Retirement  Obligations." The loss before the
cumulative  effect  was $11.1  million in the first  half of 2003,  compared  to
income of $16.9  million for the same period of 2002.  The lower  results in the
second  quarter  and the first six months of 2003 before the  cumulative  effect
reflected higher nuclear operating costs and lower operating revenues which were
partially offset by lower fuel, purchased power,  depreciation and amortization,
and financing costs.

          Operating  revenues  decreased by $34.3 million or 13.7% in the second
quarter and $55.1 million or 10.9% in the first six months of 2003 from the same
periods in 2002. The lower revenues  resulted from reduced  kilowatt-hour  sales
due, in large part, to the cooler-than-normal temperatures in the second quarter
of 2003.  These results were  moderated in the first half of 2003 as compared to
the  corresponding  period of 2002 by the effects of colder weather in the first
quarter of 2003 which increased heating demands.  Kilowatt-hour  sales to retail
customers declined by 16.4% in the second quarter of 2003 and 10.2% in the first
half of 2003 from the same  periods  of 2002,  which  reduced  generation  sales
revenue by $15.5 million and $27.1 million,  respectively.  Electric  generation
services  provided to retail customers by alternative  suppliers as a percent of
total sales delivered in TE's franchise area increased 7.5 percentage  points in
the second quarter and first six months of 2003 from the  corresponding  periods
last year.

          Distribution  deliveries decreased 8.3% in the second quarter and 1.5%
in the first six months of 2003 compared to the  corresponding  periods of 2002.
Decreases  occurred  in  all  customer  sectors  (residential,   commercial  and
industrial) in the second quarter of 2003 and only  residential  sales increased
in the first half of 2003.  As a result,  revenues from  electricity  throughput
decreased by $10.8 million in the second quarter of 2003 from the second quarter
of 2002. Revenues from electricity  throughput  increased by $9.8 million in the
first six months of 2003 due to an  increase  in  industrial  sales  revenues of
$10.6 million which reflected the effect of higher unit prices  partially offset
by a 3.1% kilowatt-hour sales decrease as compared to the same period of 2002.

          Transition  plan  incentives,   provided  to  customers  to  encourage
switching to alternative  energy providers,  reduced operating  revenues by $1.2
million in the second  quarter and $3.4  million in the first six months of 2003
compared with the same periods last year. These revenue  reductions are deferred
for future  recovery under TE's  transition  plan and do not  materially  affect
current period earnings.

          Sales revenues from wholesale  customers decreased by $6.3 million and
$27.4 million  (primarily to FES) in the second quarter and the first six months
of 2003  compared  with  the  same  periods  in  2002,  due to  reduced  nuclear
generation from the extended  outage of the Davis-Besse  Plant and a longer than
planned refueling outage at Perry Plant.  Available nuclear generation  declined
32.4% in the second  quarter and 30.8% in the first half of 2003 compared to the
corresponding periods of 2002.

          Changes in electric  generation sales and  distribution  deliveries in
the second  quarter and the first half of 2003 from the second quarter and first
half of 2002 are summarized in the following table:

          Changes in Kilowatt-Hour Sales          Three Months      Six Months
          --------------------------------------------------------------------
          Increase (Decrease)
          Electric Generation:
            Retail                                   (16.4)%          (10.2)%
            Wholesale.............................   (17.1)%          (23.2)%
          -------------------------------------------------------------------
          Total Electric Generation Sales.........   (16.7)%          (15.9)%
          ===================================================================
          Distribution Deliveries:
            Residential                              (10.2)%            1.3%
            Commercial                               (12.4)%           (1.0)%
            Industrial............................    (6.0)%           (3.1)%
          -------------------------------------------------------------------
          Total Distribution Deliveries...........    (8.3)%           (1.5)%
          ===================================================================


       Operating Expenses and Taxes

          Total  operating  expenses and taxes  decreased by $4.6 million in the
second  quarter and $20.1  million in the first six months of 2003 from the same
periods in 2002.  The following  table  presents  changes from the prior year by
expense category.

                                       2

<PAGE>


      Operating Expenses and Taxes - Changes          Three Months   Six Months
      -------------------------------------------------------------------------
      Increase (Decrease)                                     (In millions)
      Fuel.........................................    $   (1.7)      $   (5.4)
      Purchased power costs........................        (5.1)         (13.3)
      Nuclear operating costs......................        22.5           13.4
      Other operating costs........................         1.1            8.0
      ------------------------------------------------------------------------
        Total operation and maintenance expenses...        16.8            2.7

      Provision for depreciation and amortization..        (2.7)          (4.8)
      General taxes................................         0.5            1.8
      Income taxes.................................       (19.2)         (19.8)
      -------------------------------------------------------------------------
        Net decrease in operating expenses and taxes    $  (4.6)      $  (20.1)
      =========================================================================

          Lower  fuel  costs  in the  second  quarter  and  first  half of 2003,
compared  with the same  quarter and six months of 2002,  resulted  from reduced
nuclear  generation  (down 32.4% and 30.8%,  respectively).  The lower purchased
power costs  reflected  fewer  kilowatt-hours  required for customer needs which
more than offset an increase in unit costs.  Increased  nuclear  costs  resulted
from  additional  incremental  costs  associated  with the extended  Davis-Besse
outage and unplanned  work  performed  during the Perry nuclear  plant's  56-day
refueling outage (19.91% ownership) in the second quarter of 2003, compared with
the 24-day  refueling  outage at Beaver Valley Unit 2 (19.91%  ownership) in the
first quarter of 2002.  The increase in other  operating  costs resulted in part
from higher employee benefit costs.

          Charges for depreciation and amortization decreased by $2.7 million in
the second  quarter of 2003,  compared with the second quarter of 2002 primarily
from three factors - higher shopping incentive  deferrals ($1.2 million),  lower
charges resulting from the implementation of SFAS 143 ($4.5 million) and revised
service  life  assumptions  for  generating  plants  ($2.6  million).  Partially
offsetting  these  decreases were increased  amortization  of regulatory  assets
being  recovered  under TE's  transition  plan ($3.4  million),  recognition  of
depreciation  on the Bay Shore  generating  plant ($1.2  million) which had been
held pending sale in the second quarter of 2002 but was subsequently retained by
FirstEnergy in the fourth quarter of 2002 and reduced regulatory asset deferrals
($0.7 million).

          In the  first  six  months  of  2003,  depreciation  and  amortization
decreased  by $4.8  million  compared to the  corresponding  period of 2002 as a
result of the same factors which impacted the second quarter comparison - higher
shopping  incentive  deferrals  ($3.4  million),  lower charges  resulting  from
implementation  of SFAS 143 ($8.2 million) and revised service life  assumptions
($5.0 million). Partially offsetting these decreases were increased amortization
of regulatory  assets being recovered under TE's transition plan ($7.7 million),
recognition of depreciation on the Bay Shore generating plant ($2.4 million) and
reduced regulatory asset deferrals ($1.6 million).

       Net Interest Charges

          Net interest  charges  continued to trend  lower,  decreasing  by $3.5
million in the second  quarter  and $8.2  million in the first half of 2003 from
the same periods last year,  reflecting  security  redemptions and  refinancings
since the beginning of the second quarter of 2002.

       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 $25.5 million. TE identified  applicable legal
obligations as defined under the new accounting standard for nuclear power plant
decommissioning and reclamation of a sludge disposal pond at the Bruce Mansfield
Plant. As a result of adopting SFAS 143 in January 2003,  asset retirement costs
of $41.1  million were  recorded as part of the  carrying  amount of the related
long-lived asset, offset by accumulated  depreciation of $5.5 million. The asset
retirement  obligation  liability  at the date of  adoption  was  $172  million,
including  accumulated  accretion for the period from the date the liability was
incurred to the date of  adoption.  As of December  31,  2002,  TE had  recorded
decommissioning liabilities of $180.8 million, including unrealized gains on the
decommissioning  trust funds of $1.9 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 $43.8
million increase to income, or $25.6 million net of income taxes.

CAPITAL RESOURCES AND LIQUIDITY

          TE's cash  requirements in 2003 for operating  expenses,  construction
expenditures,  scheduled debt  maturities and preferred  stock  redemptions  are
expected to be met without  significantly  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.

                                       3

<PAGE>

       Changes in Cash Position

          As  of  June  30,  2003,  TE  had  $10.3  million  of  cash  and  cash
equivalents,  compared  with $20.7  million as of December 31,  2002.  The major
sources for changes in these balances are summarized below.

       Cash Flows From Operating Activities

          Cash  provided by (used for)  operating  activities  during the second
quarter and first six months of 2003, compared with the corresponding periods in
2002 were as follows:

                                     Three Months Ended      Six Months Ended
                                          June 30,                June 30,
        Operating Cash Flows          2003       2002         2003        2002
        ------------------------------------------------------------------------
                        (In millions)
        Cash earnings (1)........      $24       $ 52         $ 62        $ 87
        Working capital and other       (9)       (76)         (77)        (46)
        ------------------------------------------------------------------------

        Total....................      $15       $(24)        $(15)       $ 41
        ========================================================================

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


          Net cash provided  from  operating  activities  was $15 million in the
second  quarter  and $15  million  of net cash  used in the  first  half of 2003
compared with $24 million and $41 million,  respectively,  in the  corresponding
periods of 2002. The second quarter increase in funds from operating  activities
resulted from a $67 million decrease in cash used for working capital.

       Cash Flows From Financing Activities

          In the  second  quarter  of 2003,  net cash  provided  from  financing
activities  decreased to $22 million  from $34 million in the second  quarter of
2002.  This  decrease  in cash  provided  from  financing  activities  primarily
resulted from lower short-term borrowings from associated companies and a slight
reduction in security redemptions and repayments.

          TE had approximately  $21.1 million of cash and temporary  investments
and approximately $281.2 million of short-term indebtedness as of June 30, 2003.
TE is currently  precluded from issuing first mortgage bonds or preferred  stock
based upon applicable earnings coverage tests as of June 30, 2003.

       Cash Flows From Investing Activities

          Net cash used for investing  activities  increased $17 million between
the second  quarter of 2003 and the same  quarter of 2002 due to a reduction  in
2002 in the Shippingport Capital Trust investment.

          During the second  half of 2003,  capital  requirements  for  property
additions and capital leases are expected to be about $34 million,  including $6
million for nuclear fuel. TE has additional  requirements of  approximately  $34
million to meet  sinking  fund  requirements  for  preferred  stock and maturing
long-term  debt  during  the  remainder  of 2003.  These cash  requirements  are
expected to be satisfied from internal cash and short-term credit arrangements.

          On  July  25,  2003,  Standard  &  Poor's  (S&P)  issued  comments  on
FirstEnergy's  debt ratings in light of the latest  extension of the Davis-Besse
and the NJBPU decision on the JCP&L rate case. S&P noted that  additional  costs
from the Davis-Besse outage extension,  the NJBPU ruling on recovery of deferred
energy costs and additional capital investments  required to improve reliability
in the New Jersey shore  communities  will adversely affect  FirstEnergy's  cash
flow and deleveraging plans. S&P noted that it continues to assess FirstEnergy's
plans to determine if projected  financial measures are adequate to maintain its
current rating.

          On August 7, 2003, S&P affirmed its "BBB" corporate  credit rating for
FirstEnergy. However, S&P stated that although FirstEnergy generates substantial
free cash, that its strategy for reducing debt had deviated  substantially  from
the one  presented  to S&P around the time of the GPU  merger  when the  current
rating was assigned.  S&P further noted that their  affirmation of FirstEnergy's
corporate credit rating was based on the assumption that FirstEnergy  would take
appropriate steps quickly to maintain its investment grade ratings including the
issuance of equity or possible sale of assets. Key issues being monitored by S&P
include  the  restart of  Davis-Besse,  FirstEnergy's  liquidity  position,  its
ability to  forecast  provider-of-last-resort  load and the  performance  of its
hedged portfolio and continued capture of merger synergies.  On August 11, 2003,
S&P stated that a recent U.S. District Court ruling (see  Environmental  Matters
below) with  respect to the Sammis Plant is negative  for  FirstEnergy's  credit
quality.

                                       4

<PAGE>

          On August 14, 2003,  Moody's Investors Service placed the debt ratings
of FirstEnergy and all of its subsidiaries under review for possible  downgrade.
Moody's  stated  that the review was  prompted  by:  (1)  weaker  than  expected
operating performance and cash flow generation;  (2) less progress than expected
in reducing debt; (3) continuing high leverage  relative to its peer group;  and
(4) negative impact on cash flow and earnings from the continuing  nuclear plant
outage  at  Davis-Besse.   Moody's  further  stated  that,  in  anticipation  of
Davis-Besse returning to service in the near future and FirstEnergy's continuing
to significantly  reduce debt and improve its financial  profile,  "Moody's does
not expect that the outcome of the review  will result in  FirstEnergy's  senior
unsecured debt rating falling below investment-grade."

       Pension and Other Postretirement Benefits

          As a result of GPU  Service  Inc.  merging  with  FirstEnergy  Service
Company  in the second  quarter  of 2003,  operating  company  employees  of GPU
Service were transferred to JCP&L, Met-Ed and Penelec. Accordingly,  FirstEnergy
requested  an  actuarial  study to update the pension and other  post-employment
benefit (OPEB) assets and liabilities for each of its subsidiaries. Based on the
actuary's  report,  TE's  accrued  pension  and OPEB  costs as of June 30,  2003
decreased by $3.4 million and $24.5 million, respectively.

       Other Obligations

          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 June 30, 2003,  the present value of these sale
and leaseback  operating lease commitments,  net of trust  investments,  totaled
$474 million.  TE sells  substantially  all of its retail customer  receivables,
which provided $49 million of off-balance sheet financing as of June 30, 2003.

EQUITY PRICE RISK

          Included  in  TE's  nuclear   decommissioning  trust  investments  are
marketable equity securities carried at their market value of approximately $107
million and $90 million as of June 30, 2003 and December 31, 2002, respectively.
A hypothetical  10% decrease in prices quoted by stock exchanges would result in
a $11 million reduction in fair value as of June 30, 2003.

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 Ohio 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 Public
Utilities Commission of Ohio (PUCO) and the Federal Energy Regulatory Commission
for recovery from customers in future periods and,  without such  authorization,
would have been  charged to income when  incurred.  Regulatory  assets  declined
$41.0  million  to $537.3  million  as of June 30,  2003 from the  balance as of
December 31, 2002, resulting from recovery of transition plan regulatory assets.

          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 that 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.

       Davis-Besse Restoration

          On April 30, 2002, the Nuclear Regulatory Commission (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 is 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, leading to
the NRC's approval of restart of the plant.

                                       5

<PAGE>

          Restart  activities  include both hardware and management  issues.  In
addition to refurbishment  and installation  work at the plant,  FirstEnergy has
made  significant  management and human  performance  changes with the intent of
establishing  the proper  safety  culture  throughout  the  workforce.  Work was
completed on the reactor head during 2002 and is continuing on efforts  designed
to  enhance  the  unit's  reliability  and  performance.   FirstEnergy  is  also
accelerating  maintenance  work that had been planned for future  refueling  and
maintenance  outages.  At a meeting with the NRC in November  2002,  FirstEnergy
discussed  plans to test the  bottom of the  reactor  for leaks and to install a
state-of-the-art  leak-detection  system  around  the  reactor.  The  additional
maintenance  work  being  performed  has  expanded  the  previous  estimates  of
restoration  work.  FirstEnergy  anticipates  that  the unit  will be ready  for
restart  in the  fall of 2003.  The NRC  must  authorize  restart  of the  plant
following  its formal  inspection  process  before the unit can be  returned  to
service.  While the additional  maintenance work has delayed FirstEnergy's plans
to reduce post-merger debt levels  FirstEnergy  believes such investments in the
unit's future safety,  reliability and performance to be essential.  Significant
delays in  Davis-Besse's  return to  service,  which  depends on the  successful
resolution of the management and technical issues as well as NRC approval, could
trigger an  evaluation  for  impairment  of the nuclear  plant (see  Significant
Accounting Policies below).

          Incremental  costs  associated  with the extended  Davis-Besse  outage
(TE's  share - 48.62%)  for the second  quarter and first six months of 2003 and
2002 were as follows:


                                      Three Months Ended       Six Months Ended
Costs of Davis-Besse Extended Outage       June 30                 June 30
--------------------------------------------------------------------------------
                                       2003       2002         2003        2002
                                       ----       ----         ----        ----
                                                    (In millions)
Incremental Pre-Tax Expense
  Replacement power                    $41.1      $33.6       $  93.4      $33.6
  Maintenance                           22.4       12.1          58.6       12.1
--------------------------------------------------------------------------------
      Total                            $63.5      $45.7        $152.0      $45.7
================================================================================

Capital Expenditures                  $  2.4      $12.0      $    2.4      $12.0
================================================================================


          It is anticipated that an additional $22 million in maintenance  costs
will be expended over the remainder of the Davis-Besse outage. Replacement power
costs are  expected  to be $15 million  per month in the  non-summer  months and
$20-25 million per month during the summer months of July and August.

          FirstEnergy  has  hedged the  on-peak  replacement  energy  supply for
Davis-Besse for the expected length of the outage.

       Environmental Matters

          TE believes it is in compliance  with the current sulfur dioxide (SO2)
and  nitrogen  oxide  (NOx)  reduction  requirements  under  the  Clean  Air Act
Amendments of 1990. In 1998, the Environmental Protection Agency (EPA) finalized
regulations  requiring additional NOx reductions in the future from our Ohio and
Pennsylvania  facilities.  Various  regulatory  and judicial  actions have since
sought to further define NOx reduction requirements (see Note 2C - Environmental
Matters).  TE continues to evaluate its  compliance  plans and other  compliance
options.

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

          In  December  2000,  the EPA  announced  it  would  proceed  with  the
development of  regulations  regarding  hazardous air  pollutants  from electric
power  plants.  The EPA  identified  mercury as the  hazardous  air pollutant of
greatest  concern.  The EPA  established  a schedule to propose  regulations  by
December 2003 and issue final  regulations  by December 2004. The future cost of
compliance with these regulations may be substantial.


          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

                                       6

<PAGE>

regulation.   The  EPA  has  issued  its  final  regulatory  determination  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.

          TE believes it is in compliance with the current SO2 and NOx reduction
requirements  under the Clean Air Act  Amendments of 1990.  SO2  reductions  are
being achieved by burning  lower-sulfur  fuel,  generating more electricity from
lower-emitting  plants,  and/or using  emission  allowances.  NOx reductions 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'  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  and the
District of Columbia,  including New Jersey,  Ohio and Pennsylvania,  based on a
conclusion  that such NOx  emissions  are  contributing  significantly  to ozone
pollution in the eastern United States.  State  Implementation  Plans (SIP) must
comply by May 31, 2004 with individual state NOx budgets established by the EPA.
Pennsylvania  submitted a SIP that requires  compliance  with the NOx budgets at
the Companies'  Pennsylvania  facilities by May 1, 2003 and Ohio submitted a SIP
that requires  compliance with the NOx budgets at the Companies' Ohio facilities
by May 31, 2004.

          TE has been named as a "potentially  responsible party" (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,  potential  environmental  liabilities  have been  recognized  on the
Consolidated  Balance Sheet as of June 30, 2003, 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 total accrued
liabilities of approximately $0.2 million as of June 30, 2003.

          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 its earnings and competitive position to
the extent TE 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.  TE  believes  it is in  material
compliance  with  existing  regulations,  but is unable to predict  how and when
applicable environmental regulations may change and what, if any, the effects of
any such change would be.

       Legal Matters

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

SIGNIFICANT ACCOUNTING POLICIES

          TE prepares its consolidated  financial  statements in accordance with
accounting  principles  that  are  generally  accepted  in  the  United  States.
Application  of these  principles  often  requires  a high  degree of  judgment,
estimates and assumptions that affect TE's 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 those 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 the  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.  As of June 30,  2003,  TE's  regulatory
assets totaled $537.3 million. 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.


                                       7

<PAGE>


       Revenue Recognition

          TE follows the accrual method of accounting for revenues,  recognizing
revenue  for  kilowatt-hours  that have been  delivered  but not yet been billed
through the end of the accounting period. The determination of unbilled revenues
requires management to make various estimates including:

          o  Net energy generated or purchased for retail load
          o  Losses of energy over distribution lines
          o  Allocations to distribution companies within the FirstEnergy system
          o  Mix of kilowatt-hour usage by residential, commercial and
             industrial customers
          o  Kilowatt-hour usage of customers receiving electricity from
             alternative suppliers

       Pension and Other Postretirement Benefits Accounting

          FirstEnergy's  reported  costs of providing  non-contributory  defined
pension and OPEB benefits 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.
Pension  and OPEB costs may also be  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,  "Employers'  Accounting for Pensions" and
SFAS  106,  "Employers'  Accounting  for  Postretirement   Benefits  Other  Than
Pensions," 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 the significant decline in corporate
bond yields and interest rates in general during 2002,  FirstEnergy  reduced the
assumed discount rate as of December 31, 2002 to 6.75% from 7.25% used in 2001.

          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.  The market values of  FirstEnergy's  pension assets
have been affected by sharp  declines in the equity markets since  mid-2000.  In
2002  and  2001,   plan  assets   earned   (11.3)%  and  (5.5)%,   respectively.
FirstEnergy's  pension  costs in 2002 were  computed  assuming a 10.25%  rate of
return on plan assets. As of December 31, 2002 the assumed return on plan assets
was reduced to 9.00% based upon  FirstEnergy's  projection of future returns and
pension trust investment allocation of approximately 60% large cap equities, 10%
small cap equities and 30% bonds.

          Based on pension  assumptions  and pension  plan assets as of December
31, 2002,  FirstEnergy  will not be required to fund its pension  plans in 2003.
While OPEB plan assets have also been  affected by sharp  declines in the equity
market,  the impact is not as  significant  due to the relative size of the plan
assets.  However,  health care cost trends have significantly increased and will
affect future OPEB costs.  The 2003 composite  health care trend rate assumption
is approximately  10%-12% gradually decreasing to 5% in later years, compared to
the 2002 assumption of approximately 10% in 2002,  gradually decreasing to 4%-6%
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 developing  FirstEnergy's  restructuring  plan, the PUCO determined
allowable  transition costs based on amounts  recorded on the EUOC's  regulatory
books.  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.

                                       8

<PAGE>

       Long-Lived Assets

          In  accordance  with  SFAS  144,  "Accounting  for the  Impairment  or
Disposal of Long-Lived Assets," TE periodically  evaluates its long-lived assets
to determine  whether  conditions  exist that would  indicate  that the carrying
value of an asset may 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 other than of a temporary
nature 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).

       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
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, an impairment for goodwill must be recognized
in the financial  statements.  If impairment were to occur, TE would recognize a
loss -  calculated  as the  difference  between  the  implied  fair  value  of a
reporting  unit's  goodwill and the carrying value of the goodwill.  TE's annual
review was  completed in the third  quarter of 2002.  The results of that review
indicated no impairment of goodwill.  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
its future  evaluations of goodwill.  As of June 30, 2003, TE had  approximately
$505 million of goodwill.

RECENTLY ISSUED ACCOUNTING STANDARD NOT YET IMPLEMENTED

       FIN 46, "Consolidation of Variable Interest Entities - an interpretation
       of ARB 51"

          In January 2003,  the FASB issued this  interpretation  of ARB No. 51,
"Consolidated Financial Statements". The new interpretation provides guidance on
consolidation of variable interest entities (VIEs), generally defined as certain
entities  in  which  equity  investors  do not  have  the  characteristics  of a
controlling  financial interest or do not have sufficient equity at risk for the
entity to finance  its  activities  without  additional  subordinated  financial
support  from other  parties.  This  Interpretation  requires an  enterprise  to
disclose  the  nature  of its  involvement  with a VIE if the  enterprise  has a
significant  variable  interest  in  the  VIE  and to  consolidate  a VIE if the
enterprise is the primary  beneficiary.  VIEs created after January 31, 2003 are
immediately subject to the provisions of FIN 46. VIEs created before February 1,
2003 are subject to this  interpretation's  provisions  in the first  interim or
annual  reporting  period  beginning  after June 15, 2003 (TE's third quarter of
2003).  The FASB also  identified  transitional  disclosure  provisions  for all
financial statements issued after January 31, 2003.

          TE currently has transactions  which may fall within the scope of this
interpretation and which are reasonably  possible of meeting the definition of a
VIE in accordance with FIN 46. TE currently  consolidates  the majority of these
entities and believes it will continue to consolidate  following the adoption of
FIN 46. One of these entities TE is currently  consolidating is the Shippingport
Capital Trust,  which reacquired a portion of the off-balance  sheet debt issued
in connection with the sale and leaseback of its interest in the Bruce Mansfield
Plant.  Ownership of the trust includes a 4.85 percent interest by nonaffiliated
parties and a 0.34 percent  equity  interest by Toledo Edison  Capital  Corp., a
majority owned subsidiary.

       EITF Issue No. 01-08, "Determining whether an Arrangement Contains a
       Lease"

          In May 2003, the EITF reached a consensus  regarding when arrangements
contain a lease. Based on the EITF consensus, an arrangement contains a lease if
(1)  it  identifies  specific  property,   plant  or  equipment  (explicitly  or
implicitly),  and (2) the  arrangement  transfers  the right to the purchaser to
control the use of the  property,  plant or  equipment.  The  consensus  will be
applied prospectively to arrangements committed to, modified or acquired through
a business combination,  beginning in the third quarter of 2003. TE is currently
assessing the new EITF  consensus and has not yet  determined  the impact on its
financial position or results of operations following adoption.

                                       9

<PAGE>


PART II. OTHER INFORMATION
--------------------------

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

(a)  Exhibits

           Exhibit
           Number
           ------

TE

            31.1  Certification letter from chief executive officer, as adopted
                  pursuant to Section 302 of the Sarbanes-Oxley Act.
            31.2  Certification letter from chief financial officer, as adopted
                  pursuant to Section 302 of the Sarbanes-Oxley Act.
            32.1  Certification letter from chief executive officer and chief
                  financial officer, as adopted pursuant to Section 906
                  of the Sarbanes-Oxley Act.

          Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, TE
          has not filed as an exhibit to this Form  10-Q/A any  instrument  with
          respect to long-term debt if the total amount of securities authorized
          thereunder  does not exceed 10% of the total  assets of TE, but hereby
          agrees to furnish to the Commission on request any such documents.

(b)  Reports on Form 8-K

         TE

          TE filed  eight  reports on Form 8-K since  March 31,  2003.  A report
dated April 16, 2003  reported  Davis-Besse  information.  A report dated May 1,
2003 reported an updated Davis-Besse ready for restart schedule.  A report dated
May 9, 2003 reported  updated  Davis-Besse  information.  A report dated June 5,
2003,  reported updated  Davis-Besse  information.  A report dated July 24, 2003
reported an updated Davis-Besse ready for restart schedule and cost estimates. A
report dated August 5, 2003 reported the pending restatement of 2002 FE, OE, CEI
and TE  financial  statements  and  restatement  and  reaudit of 2001 CEI and TE
financial  statements.  A report  dated  August 7,  2003  reported  the  pending
restatement and reaudit of 2000 CEI and TE financial statements.  A report dated
September  12, 2003  reported  that FE, OE, CEI and TE have received an informal
data request from the Securities and Exchange  Commission  related to the recent
restatement of their 2002 financial statements.

                                       10


<PAGE>



                                   SIGNATURE



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



September 24, 2003







                                           THE TOLEDO EDISON COMPANY
                                           -------------------------
                                                   Registrant



                                                /s/  Harvey L. Wagner
                                      -----------------------------------------
                                                     Harvey L. Wagner
                                              Vice President and Controller
                                                Chief Accounting Officer

                                       11