UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                              Washington, DC 20549
                                    FORM 10-Q

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

          For the quarterly period ended...September 30, 1998..........

                                       OR

          [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
                         SECURITIES EXCHANGE ACT OF 1934

          For the transition period from.........to...................

         Commission file number..................1-1401...................

         .......................PECO Energy Company.......................
         (Exact name of registrant as specified in its charter)

         ..........Pennsylvania................ 23-0970240................
         (State or other jurisdiction of     (I.R.S. Employer
         incorporation or organization)      Identification No.)

         ....2301 Market Street, Philadelphia, PA..........19103..........
         (Address of principal executive offices)       (Zip Code)

         ........................(215)841-4000............................
         (Registrant's telephone number, including area code)


         Indicate by check mark whether the registrant (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  the  number of  shares  outstanding  of each of the  issuer's
         classes of common stock as of the latest practicable date:

         The Company  had  224,045,506  shares of common  stock  outstanding  on
         September 30, 1998.


<PAGE>


<TABLE>
                                                 PART I. FINANCIAL INFORMATION
                                                  ITEM 1. FINANCIAL STATEMENTS
                                          PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
                                           CONDENSED CONSOLIDATED STATEMENTS OF INCOME
                                                           (Unaudited)
                                                      (Millions of Dollars)


<CAPTION>
                                                                    3 Months Ended          9 Months Ended
                                                                     September 30,           September 30,
                                                              -----------------------   ----------------------
                                                                 1998         1997         1998         1997
                                                              ---------    ----------   ---------    ---------
OPERATING REVENUES
<S>                                                            <C>          <C>          <C>          <C>     
     Electric                                                  $1,731.0     $1,232.2     $3,858.8     $3,146.1
     Gas                                                           42.9         46.0        295.7        327.8
                                                              ---------    ----------    ---------    ---------
     TOTAL OPERATING REVENUES                                   1,773.9      1,278.2      4,154.5      3,473.9
                                                              ---------    ----------    ---------    ---------
OPERATING EXPENSES
     Fuel and Energy Interchange                                  726.0        354.1      1,446.6        954.2
     Operating and Maintenance                                    296.1        313.8        840.2        912.0
     Depreciation and Amortization                                153.2        143.5        468.8        433.6
     Taxes Other Than Income Taxes                                 52.3         78.7        206.2        234.3
                                                              ---------    ----------    ---------    ---------
     TOTAL OPERATING EXPENSES                                   1,227.6        890.1      2,961.8      2,534.1
                                                              ---------    ----------    ---------    ---------
OPERATING INCOME                                                  546.3        388.1      1,192.7        939.8
                                                              ---------    ----------    ---------    ---------
OTHER INCOME AND DEDUCTIONS
     Interest Expense                                             (83.1)       (93.2)      (259.1)      (279.3)
     Company Obligated Mandatorily Redeemable
       Preferred Securities of a Partnership                       (7.5)        (7.7)       (23.3)       (21.3)
     Allowance for Funds Used During Construction                   2.1          4.0          8.4         18.4
     Settlement of Salem Litigation                                 -            -            -           69.8
     Other, Net                                                    (9.5)        (5.2)       (42.2)       (14.3)
                                                              ---------    ----------    ---------    ---------
     TOTAL OTHER INCOME AND DEDUCTIONS                            (98.0)      (102.1)      (316.2)      (226.7)
                                                              ---------    ----------    ---------    ---------
INCOME BEFORE INCOME TAXES                                        448.3        286.0        876.5        713.1
                                                              ---------    ----------    ---------    ---------
INCOME TAXES                                                      174.6        128.0        337.7        319.3
                                                              ---------    ----------    ---------    ---------
NET INCOME                                                        273.7        158.0        538.8        393.8
PREFERRED STOCK DIVIDENDS                                           3.2          4.5          9.8         13.5
                                                              ---------    ----------    ---------    ---------
EARNINGS APPLICABLE TO COMMON STOCK                            $  270.5     $  153.5     $  529.0     $  380.3
                                                              =========    ==========    =========    =========

AVERAGE SHARES OF COMMON STOCK
     OUTSTANDING (Millions)                                       223.1        222.5        222.8        222.5


BASIC EARNINGS PER AVERAGE COMMON SHARE (Dollars)             $    1.21     $   0.69     $   2.37     $   1.71

DILUTED EARNINGS PER AVERAGE COMMON SHARE (Dollars)           $    1.20     $   0.69     $   2.36     $   1.71

DIVIDENDS PER AVERAGE COMMON SHARE (Dollars)                  $    0.25     $   0.45     $   0.75     $   1.35


<FN>
                                     See Notes to Condensed Consolidated Financial Statements.

</FN>
</TABLE>

<PAGE>




<TABLE>
                                            PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
                                                CONDENSED CONSOLIDATED BALANCE SHEETS
                                                        (Millions of Dollars)


<CAPTION>
                                                                          September 30,       December 31,
                                                                              1998                1997
                                                                          ------------        ------------
                                                                           (Unaudited)
ASSETS

UTILITY PLANT
<S>                                                                         <C>                 <C>       
Electric - Transmission & Distribution                                      $  3,682.5          $  3,617.7
Electric - Generation                                                          1,479.4             1,434.9
Gas                                                                            1,099.6             1,071.8
Common                                                                           322.1               302.7
                                                                            ----------          ----------
                                                                               6,583.6             6,427.1
Less Accumulated Provision for Depreciation                                    2,833.6             2,690.8
                                                                            ----------          ----------
                                                                               3,750.0             3,736.3
Nuclear Fuel, net                                                                149.0               147.4
Construction Work in Progress                                                    702.4               611.2
Leased Property, net                                                             163.6               175.9
                                                                            ----------          ----------
                                                                               4,765.0             4,670.8
                                                                            ----------          ----------

CURRENT ASSETS
Cash and Temporary Cash Investments                                               43.9                33.4
Accounts Receivable, net
     Customer                                                                    233.1               173.3
     Other                                                                       234.3               140.0
Inventories, at average cost
     Fossil Fuel                                                                  87.5                84.9
     Materials and Supplies                                                       84.1                90.9
Deferred Generation Costs Recoverable in Current Rates                           104.3               424.5
Deferred Energy Costs - Gas                                                       18.0                35.7
Other                                                                             72.5                20.1
                                                                            ----------          ----------
                                                                                 877.7             1,002.8
                                                                            ----------          ----------
DEFERRED DEBITS AND OTHER ASSETS
Competitive Transition Charge                                                  5,274.6             5,274.6
Recoverable Deferred Income Taxes                                                614.2               590.3
Deferred Non-Pension Postretirement Benefits Costs                                92.5                97.4
Investments                                                                      512.0               515.8
Loss on Reacquired Debt                                                           78.8                83.9
Other                                                                            133.2               121.0
                                                                            ----------          ----------
                                                                               6,705.3             6,683.0
                                                                            ----------          ----------
TOTAL                                                                       $ 12,348.0          $ 12,356.6
                                                                            ==========          ==========
<FN>

                                     See Notes to Condensed Consolidated Financial Statements.
</FN>

                                                     (continued on next page)
</TABLE>

<PAGE>



<TABLE>
                                             PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
                                                CONDENSED CONSOLIDATED BALANCE SHEETS
                                                        (Millions of Dollars)
                                                             (continued)


<CAPTION>
                                                                          September 30,       December 31,
                                                                              1998                1997
                                                                          ------------        ------------
                                                                           (Unaudited)
CAPITALIZATION AND LIABILITIES

CAPITALIZATION
Common Shareholders' Equity
<S>                                                                         <C>                 <C>       
     Common Stock (No Par)                                                  $  3,564.1          $  3,517.7
     Other Paid-In Capital                                                         1.2                 1.2
     Retained Deficit                                                           (444.9)             (792.2)
Preferred and Preference Stock
     Without Mandatory Redemption                                                137.5               137.5
     With Mandatory Redemption                                                    92.7                92.7
Company Obligated Mandatorily Redeemable
     Preferred Securities of a Partnership                                       349.4               352.1
Long-Term Debt                                                                 3,589.9             3,853.1
                                                                            ----------          ----------
                                                                               7,289.9             7,162.1
                                                                            ----------          ----------
CURRENT LIABILITIES
Notes Payable, Bank                                                              116.0               401.5
Long-Term Debt Due Within One Year                                               256.4               247.1
Capital Lease Obligations Due Within One Year                                     70.9                55.8
Accounts Payable                                                                 288.1               306.9
Taxes Accrued                                                                    276.6                66.4
Interest Accrued                                                                  80.5                77.9
Dividends Payable                                                                 20.2                17.0
Deferred Income Taxes                                                             42.9               185.7
Other                                                                            220.1               260.4
                                                                            ----------          ----------
                                                                               1,371.7             1,618.7
                                                                            ----------          ----------
DEFERRED CREDITS AND OTHER LIABILITIES
Capital Lease Obligations                                                         92.7               120.1
Deferred Income Taxes                                                          2,393.9             2,297.1
Unamortized Investment Tax Credits                                               304.5               318.1
Pension Obligation                                                               211.6               211.6
Non-Pension Postretirement Benefits Obligation                                   342.7               324.8
Other                                                                            341.0               304.1
                                                                            ----------          ----------
                                                                               3,686.4             3,575.8
                                                                            ----------          ----------
COMMITMENTS AND CONTINGENCIES (NOTE 7)

TOTAL                                                                       $ 12,348.0          $ 12,356.6
                                                                            ==========          ==========


<FN>
                                     See Notes to Condensed Consolidated Financial Statements.
</FN>
</TABLE>


<PAGE>



<TABLE>
                                             PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
                                           CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
                                                          (Unaudited)
                                                     (Millions of Dollars)

<CAPTION>
                                                                                         9 Months Ended
                                                                                          September 30,
                                                                                    ---------------------------------
                                                                                        1998                  1997
                                                                                    ----------             ----------

CASH FLOWS FROM OPERATING ACTIVITIES

<S>                                                                                 <C>                    <C>      
NET INCOME                                                                          $   538.8              $   393.8
Adjustments to Reconcile Net Income to Net Cash
     Provided by Operating Activities:
Depreciation and Amortization                                                           514.2                  494.4
Deferred Income Taxes                                                                   (69.4)                  (1.0)
Deferred Energy Costs                                                                    17.7                   12.9
Salem Litigation Settlement                                                               -                    (69.8)
Changes in Working Capital:
     Accounts Receivable                                                               (154.1)                 (30.3)
     Inventories                                                                          4.2                   11.7
     Accounts Payable                                                                   (18.8)                   4.0
     Other Current Assets and Liabilities                                               120.1                   34.1
Other Items Affecting Operations                                                         96.4                   42.0
                                                                                    ----------              ---------
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES                                       1,049.1                  891.8
                                                                                    ----------              ---------

CASH FLOWS FROM INVESTING ACTIVITIES

Investment in Plant                                                                    (316.9)                (362.1)
Other Investments                                                                       (40.0)                (104.1)
                                                                                    ----------             ----------
NET CASH FLOWS USED BY INVESTING ACTIVITIES                                            (356.9)                (466.2)
                                                                                    ----------             ----------

CASH FLOWS FROM FINANCING ACTIVITIES

Change in Short-Term Debt                                                              (285.5)                (130.0)
Issuance of Common Stock                                                                 46.4                    -
Issuance of Long-Term Debt                                                                9.8                   17.2
Retirement of Long-Term Debt                                                           (265.8)                 (33.3)
Loss on Reacquired Debt                                                                   5.1                   17.5
Issuance of Company Obligated Mandatorily
     Redeemable Preferred Securities of a Partnership                                    78.1                   50.0
Retirement of Company Obligated Mandatorily
     Redeemable Preferred Securities of a Partnership                                   (80.9)                   -
Dividends on Preferred and Common Stock                                                (176.9)                (314.0)
Change in Dividends Payable                                                               3.2                    5.3
Other Items Affecting Financing                                                         (15.2)                   0.2
                                                                                    ----------             ----------
NET CASH FLOWS USED BY FINANCING ACTIVITIES                                            (681.7)                (387.1)
                                                                                    ----------             ----------
INCREASE IN CASH AND CASH EQUIVALENTS                                                    10.5                   38.5
                                                                                    ----------             ----------
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD                                         33.4                   29.2
                                                                                    ----------             ----------
CASH AND CASH EQUIVALENTS AT END OF PERIOD                                          $    43.9               $   67.7
                                                                                    ==========             ==========


<FN>
                                     See Notes to Condensed Consolidated Financial Statements.
</FN>
</TABLE>


<PAGE>

                  PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
              NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1.       BASIS OF PRESENTATION
         The  accompanying  condensed  consolidated  financial  statements as of
September  30, 1998 and for the three and nine months then ended are  unaudited,
but  include  all  adjustments  that PECO  Energy  Company  (Company)  considers
necessary for a fair presentation of such financial statements.  All adjustments
are of a normal,  recurring nature. The year-end condensed  consolidated balance
sheet data were derived from audited financial statements but do not include all
disclosures  required  by  generally  accepted  accounting  principles.  Certain
prior-year amounts have been reclassified for comparative purposes.  These notes
should  be  read  in  conjunction  with  the  Notes  to  Consolidated  Financial
Statements  in the  Company's  1997  Annual  Report to  Shareholders,  which are
incorporated  by reference in the  Company's  Annual Report on Form 10-K for the
year ended December 31, 1997 (1997 Form 10-K).

2.       RATE MATTERS
         On May 14, 1998,  the  Pennsylvania  Public  Utility  Commission  (PUC)
issued a final order (Final  Restructuring Order) approving a Joint Petition for
Settlement (Global  Settlement) filed by the Company and numerous parties to the
Company's restructuring proceeding.  The Final Restructuring Order concludes the
Company's  restructuring  proceeding  filed on April 1,  1997,  pursuant  to the
Electricity  Generation  Competition and Customer Choice Act (Competition  Act).
The Final  Restructuring  Order  provides for the  recovery of $5.26  billion of
stranded costs over a 12-year  period  beginning in 1999 with a 10.75% return on
the stranded cost balance.

         The Final  Restructuring  Order  provides  for the phase-in of customer
choice of electric  generation  suppliers (EGS) for all customers:  one-third of
the peak load of each customer class on January 1, 1999; one-third on January 2,
1999 and the  remainder on January 2, 2000.  The order also  establishes  market
share  thresholds to ensure that a minimum number of residential  and commercial
customers  choose an EGS. If less than 35% and 50% of residential and commercial
customers  have  chosen  an  EGS  by  January  1,  2001  and  January  1,  2003,
respectively,  then a number  of  customers  sufficient  to meet  the  necessary
threshold  levels  shall be randomly  selected  and assigned to an EGS through a
PUC-determined process.

         Beginning  January 1, 1999,  electric  rates will be  unbundled  into a
transmission and distribution  component,  a "transition charge" for recovery of
stranded costs and an energy and capacity charge.  Eligible customers who choose
an EGS will not be charged the energy and  capacity  charge or the  transmission
charge and instead will purchase their electric  energy supply and  transmission
at  market-based  rates from their EGS.  Also,  beginning  January 1, 1999,  the
Company will unbundle its retail electric rates for metering,  meter reading and
billing and collection  services to provide credits to those customers who elect
to have an alternative supplier perform these services.

         In  accordance  with the  Competition  Act and the Final  Restructuring
Order, all customers'  kilowatthour  (kWh) rates are capped at the year-end 1996
levels (system-wide  average of 9.96 cents/kWh) through June 2005. The rate caps
are further adjusted by the following rate  reductions.  On January 1, 1999, the
Company will reduce its retail  electric  rates by 8% from the 1996  system-wide
average  rate.  The rate  decrease  will  become 6% from  January  1, 2000 until
January 1,  2001,  when the  system-wide  average  rate cap will  revert to 9.96
cents/kWh.  The transmission and distribution  rate component will remain capped
at a system average rate of 2.98 cents/kWh through June 30, 2005.  Additionally,
generation rate caps, defined as the sum of the applicable transition charge and
shopping credit, will remain in effect through 2010.
<PAGE>
         The Final  Restructuring Order requires that on January 1, 2001, 20% of
all of the Company's residential  customers,  determined by random selection and
without regard to whether such customers are obtaining  generation  service from
an EGS,  shall be assigned to a provider of last resort  default  supplier other
than the Company through a PUC-approved bidding process.

         The Final  Restructuring  Order authorizes the Company to securitize up
to $4  billion  of its  recoverable  stranded  costs  through  the  issuance  of
transition  bonds.  The proceeds of the transition bonds are required to be used
principally to reduce qualified stranded costs and related capitalization.

         As  previously  reported  in the 1997  Form  10-K,  the  Company  filed
complaints  in federal and state  courts  relating to the  restructuring  orders
issued by the PUC in December  1997,  January 1998 and February  1998  (Original
Restructuring  Orders).  In addition,  numerous  other parties filed appeals and
cross appeals of the Original Restructuring Orders. In accordance with the terms
of the Final  Restructuring  Order, all appeals and  cross-appeals  filed by the
signatories to the Global  Settlement have been placed in a pending but inactive
status.  Such appeals and cross  appeals will be  permanently  withdrawn at such
time that the Final  Restructuring  Order is no longer subject to administrative
or judicial challenge.

         An intervenor  brought an action  asserting  that the  Competition  Act
violated the Commerce Clause of the United States Constitution.  On May 7, 1998,
the Commonwealth Court of Pennsylvania (Commonwealth Court) unanimously rejected
the claim.  The  intervenor  petitioned  the Supreme Court of  Pennsylvania  for
allowance of appeal.  On September  29, 1998,  the  Pennsylvania  Supreme  Court
denied the  petition.  The  intervenor  has until  December  28,  1998 to file a
petition for certiorari with the United States Supreme Court.

         Two original  jurisdiction actions were filed in the Commonwealth Court
claiming  that the  manner  in  which  the  Competition  Act was  passed  by the
Pennsylvania  legislature violated the Pennsylvania  Constitution.  On September
24, 1998, those claims were rejected by the  Commonwealth  Court. On October 26,
1998,  the appeal  period for those cases  expired  without any party  filing an
appeal to the Pennsylvania Supreme Court.

     3. RESTART OF SALEM GENERATING  STATION (SALEM) Public Service Electric and
Gas  Company  (PSE&G),  the  operator  of Salem Units No. 1 and No. 2, which are
42.59%  owned by the  Company,  removed  the units  from  service  in the second
quarter  of 1995.  Unit No. 2  returned  to  commercial  operation  in the third
quarter of 1997 and Unit No. 1 returned  to  commercial  operation  on April 17,
1998. The following  table  summarizes  replacement  power costs recorded in the
accompanying  Statements of Income as Fuel and Energy  Interchange and Operating
and Maintenance costs relating to the shutdown of Salem:

                                   Three Months Ended          Nine Months Ended
                                     September 30,              September 30,
                                      1998    1997              1998    1997
                                     -----   -----             -----   -----
Recorded on Accompanying
  Statements of Income (millions)

Fuel and Energy Interchange           $ -     $ 27             $ 19      $ 84

Operating and Maintenance               2       12               13        38
                                     -----   -----             -----    -----
Total                                 $ 2     $ 39             $ 32     $ 122

         For the year ending December 31, 1998, the Company expects to incur and
expense approximately $35 million of costs related to the shutdown.
<PAGE>
4.       SALES OF ACCOUNTS RECEIVABLE
         The  Company is party to an  agreement  with a  financial  institution,
under which it can sell or finance with limited recourse an undivided  interest,
adjusted daily, in up to $425 million of designated  accounts  receivable  until
November  2000.  At  September  30,  1998,  the Company had sold a $425  million
interest  in  accounts  receivable,  consisting  of a $311  million  interest in
accounts  receivable which the Company accounts for as a sale under Statement of
Financial  Accounting  Standards  (SFAS) No. 125,  "Accounting for Transfers and
Servicing of Financial Assets and  Extinguishment  of  Liabilities,"  and a $114
million interest in special  agreement  accounts  receivable which are accounted
for  as  a  long-term   note   payable.   The  Company   retains  the  servicing
responsibility  for these  receivables.  The  agreement  requires the Company to
maintain the $425 million  interest,  which, if not met, requires the Company to
deposit cash in order to satisfy such  requirements.  The Company,  at September
30, 1998,  met such  requirements.  At September  30, 1998,  the average  annual
service-charge  rate,  computed on a daily basis on the portion of the  accounts
receivable sold but not yet collected, was 5.6%.

5.       STOCK REPURCHASE
         During 1997, the Company's Board of Directors authorized the repurchase
of up to 25  million  shares  of its  common  stock  from  time to time  through
open-market,   privately  negotiated  and/or  other  types  of  transactions  in
conformity with the rules of the SEC.

         Pursuant to these authorizations,  the Company has entered into forward
purchase  agreements to be settled from time to time, at the Company's election,
on either a  physical,  net share or net cash  basis.  The amount at which these
agreements can be settled is dependent  principally upon the market price of the
Company's  common stock as compared to the forward  purchase price per share and
the number of shares to be settled.  If these  agreements  had been settled on a
net  share  basis at  September  30,  1998,  based on the  closing  price of the
Company's   common  stock  on  that  date,   the  Company  would  have  received
approximately 3,624,000 shares of Company common stock.

6.        EARNINGS PER SHARE
         Diluted  earnings per average  common share is  calculated  by dividing
earnings  applicable  to common  stock by the  average  shares  of common  stock
outstanding  after giving effect to stock options,  issuable under the Company's
Long-Term  Incentive  Plan  (LTIP),  considered  to  be  dilutive  common  stock
equivalents.  The following table shows the effect of the stock options issuable
under the  Company's  LTIP on the average  number of shares used in  calculating
diluted earnings per average common share:

                                      Three Months Ended       Nine Months Ended
                                          September 30,          September 30,
Description (Millions of shares)           1998    1997          1998    1997
--------------------------------          -----   -----         -----   -----

Average Common Shares Outstanding         223.1   222.5         222.8   222.5

Assumed Conversion of Stock Options         1.9     0.1           1.7     0.1
                                          -----   -----         -----   -----
Potential Average Dilutive
  Common Shares Outstanding               225.0   222.6         224.5   222.6

7.       COMMITMENTS AND CONTINGENCIES
         For information  regarding the Company's capital  commitments,  nuclear
insurance,  nuclear  decommissioning and spent fuel storage, energy commitments,
environmental  issues  and  litigation,  see  note 5 of  Notes  to  Consolidated
Financial Statements for the year ended December 31, 1997.
<PAGE>
         The Company has identified 28 sites where former manufactured gas plant
(MGP) activities have or may have resulted in actual site  contamination.  As of
September  30,  1998,  the Company  had  accrued  $61 million for  environmental
investigation and remediation costs, including $34 million for MGP investigation
and remediation that currently can be reasonably  estimated.  The Company cannot
predict  whether it will incur  other  significant  liabilities  for  additional
investigation  and remediation  costs at these or additional sites identified by
the Company, environmental agencies or others, or whether all such costs will be
recoverable from third parties.

     On October 15, 1998,  AmerGen  Energy  Company,  LLC  (AmerGen),  the joint
venture  between the Company and British Energy plc,  signed a definitive  asset
purchase  agreement  with GPU,  Inc.  to  purchase  Three  Mile  Island  Nuclear
Generating  Station Unit No. 1. In  connection  with the  execution of the asset
purchase agreement, the Company and British Energy plc each agreed to make their
share of capital contributions to AmerGen in order to enable AmerGen to make the
payment required at closing and, if necessary,  any additional payments required
under the asset purchase agreement.

         The Company  periodically  reviews its investments to determine whether
they are properly valued in its financial statements.

8.       ACCOUNTING MATTERS
         In June 1998, the Financial Accounting Standards Board issued Statement
of Financial  Accounting  Standards  (SFAS) No. 133,  "Accounting for Derivative
Instruments  and Hedging  Activities,"  to establish  accounting  and  reporting
standards for derivatives. The new standard requires recognizing all derivatives
as either  assets or  liabilities  on the balance  sheet at their fair value and
specifies the accounting  for changes in fair value  depending upon the intended
use of the derivative.  The new standard is effective for fiscal years beginning
after  June 15,  1999.  The  Company  expects to adopt SFAS No. 133 in the first
quarter of 2000.  The Company is in the process of evaluating the impact of SFAS
No. 133 on its financial statements.


<PAGE>
ITEM 2.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS

GENERAL
         The  Electricity   Generation   Customer  Choice  and  Competition  Act
(Competition  Act) was enacted in December 1996 providing for the  restructuring
of the electric utility industry in Pennsylvania,  including the deregulation of
utility  generation  operations and the  institution of retail  competition  for
generation  supply beginning in 1999.  Pursuant to the Competition Act, in April
1997, the Company filed with the Pennsylvania  Public Utility Commission (PUC) a
restructuring  plan in which it  identified  $7.5  billion  of  retail  electric
generation-related  stranded  costs. In May 1998, the PUC entered an Opinion and
Order (Final  Restructuring  Order) which  deregulates  the  Company's  electric
generation  operations and  authorizes the Company to recover  stranded costs of
$5.26 billion over 12 years beginning January 1, 1999.  Additionally,  the Final
Restructuring Order provides for the phase-in of customer choice between January
1, 1999 and January 2, 2000.  Following  completion of the phase-in,  all of the
Company's  customers will have the ability to choose their  electric  generation
supplier.  For additional  information  concerning the Competition Act and Final
Restructuring  Order,  see  "Management's  Discussion  and Analysis of Financial
Condition  and  Results  of  Operations"  in  the  Company's  Annual  Report  to
Shareholders for the year 1997; the Company's Annual Report on Form 10-K for the
year  ended  December  31,  1997  (1997  Form  10-K)  under  "PART  I.  ITEM  1.
BUSINESS-Deregulation and Rate Matters"; "PART II. ITEM 5. OTHER INFORMATION" of
the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 1998
(March  31,  1998  Form  10-Q);  "PART II.  ITEM 5.  OTHER  INFORMATION"  of the
Company's  Quarterly  Report on Form 10-Q for the  quarter  ended June 30,  1998
(June 30, 1998 Form 10-Q);  and under  "PART II. ITEM 5. OTHER  INFORMATION"  in
this Quarterly Report on Form 10-Q (Report).

         The rate  reductions of the Final  Restructuring  Order (8% in 1999 and
reduced to 6% in 2000) are expected to reduce the Company's revenues from future
retail  electric  sales.  The Company  believes  that its  revenues  from retail
electric sales will be further  reduced by competition  for electric  generation
services,  which will be  available  to  two-thirds  of its retail  customers by
January 2, 1999 and all retail customers by January 2, 2000.

         In light  of the  expected  impact  on  future  revenues  of the  Final
Restructuring  Order and  competition  for  electric  generation  services,  the
Company is continuing its cost  management  efforts  through a Competitive  Cost
Review  (CCR).  Through  CCR, the Company is  continuing  to conduct an in-depth
analysis and assessment of all Company expenses, capital expenditures, programs,
processes and staffing  levels.  The goal of CCR is to achieve  significant cost
savings while  maintaining high levels of service quality,  reliability,  safety
and overall performance.

         In  accordance  with the  cost-control  targets of CCR,  the Company is
committed to reducing annual operating and maintenance  expense by at least $150
million by 2001. The expense  reductions will be realized,  in part, through the
elimination of approximately 1,200 positions in 1998 and 1999.

         In April 1998, the Board of Directors  authorized the implementation of
a retirement  incentive  program and an enhanced  severance  benefit  program to
accompany targeted workforce reductions. The retirement incentive program allows
employees age 50 and older, who have been designated as excess or who are in job
classifications  facing  reduction,  to retire from the  Company.  The  enhanced
severance benefit program provides non-retiring excess employees with fewer than
ten years of  service,  benefits  equal to two  weeks  pay per year of  service.
Non-retiring  excess  employees  with  more than ten  years of  service  receive
benefits equal to three weeks pay per year of service.

         The  Company  anticipates  that it  will  incur a  one-time  charge  to
earnings  in the  fourth  quarter  of 1998 to  recognize  costs  related to CCR;
however, the magnitude of such charge is not known at this time.
<PAGE>
         The Company's future financial  condition and results of operations are
also  affected by other  factors,  such as the  operation of nuclear  generating
facilities,  wholesale sales and purchases, weather conditions and the Company's
ability to develop its investments in new ventures into profitable enterprises.

         In June 1998, the Financial Accounting Standards Board issued Statement
of Financial  Accounting  Standards  (SFAS) No. 133,  "Accounting for Derivative
Instruments  and Hedging  Activities,"  to establish  accounting  and  reporting
standards for derivatives. The new standard requires recognizing all derivatives
as either  assets or  liabilities  on the balance  sheet at their fair value and
specifies the accounting  for changes in fair value  depending upon the intended
use of the derivative.  The new standard is effective for fiscal years beginning
after  June 15,  1999.  The  Company  expects to adopt SFAS No. 133 in the first
quarter of 2000.  The Company is in the process of evaluating the impact of SFAS
No. 133 on its financial statements.


RESULTS OF OPERATIONS
EARNINGS
         Basic  earnings per average  common share for the three and nine months
ended September 30, 1998 were $1.21 and $2.37 per share, respectively,  compared
to $0.69 and $1.71 per share in 1997.  Diluted  earnings per share for the three
and nine  months  ended  September  30,  1998 were  $1.20  and $2.36 per  share,
respectively, compared to $0.69 and $1.71 per share in 1997.

         The increase in third  quarter  earnings was due primarily to increased
operating  revenues net of related fuel costs.  Third quarter 1998 earnings also
benefited  from the  return to  service  of Salem  Generating  Station  (Salem),
continued   reduction  of  operating  and   maintenance   costs,   reduction  of
uncollectible  expenses  and a  one-time  refund of gross  receipts  tax.  These
factors were partially offset by higher losses from investments in subsidiaries.
Income tax expense increased due to higher earnings but was partially offset due
to full  normalization of deferred taxes associated with deregulated  generation
plant.

         The increase in earnings for the nine months ended  September  30, 1998
was primarily due to increased operating revenues net of related fuel costs, the
return to service of Salem,  continued  reduction of operating  and  maintenance
costs and a one-time  refund of gross receipts tax. These factors were partially
offset  by the  benefit  in  1997 of the  recognition  of the  Salem  litigation
settlement  and, in 1998, by higher  losses from  investments  in  subsidiaries.
Income tax expense increased due to higher earnings but was partially offset due
to full  normalization of deferred taxes associated with deregulated  generation
plant.

OPERATING REVENUES
         Electric  revenues  increased 40% and 23% for the three and nine months
ended September 30, 1998,  respectively,  compared to 1997. The increase for the
three months was primarily due to higher revenues from wholesale sales resulting
from an increase  in energy  prices in the spot market as well as an increase in
sales volume.  Also contributing to the increase was higher revenues from retail
sales  due  to an  increase  in  sales  volume  resulting  from  warmer  weather
conditions. Partially offsetting these increases were lower average retail rates
as a result of the customer choice pilot program.

         The increase in electric  revenues for the nine months ended  September
30, 1998 was primarily due to an increase from wholesale sales resulting from an
increase  in energy  prices in the spot  market as well as an  increase in sales
volume and an increase in retail sales resulting from warmer weather conditions.
Partially offsetting the increase were lower average retail rates as a result of
the customer choice pilot program.
<PAGE>
         Gas  revenues  decreased 7% and 10% for the three and nine months ended
September  30, 1998  compared to 1997.  The  decrease  for the three  months was
primarily due to a decrease in gas transported  for customers.  The decrease for
the nine months was  primarily  due to milder  weather  conditions  in the first
quarter as well a decrease in gas transported for customers.

FUEL AND ENERGY INTERCHANGE
         Fuel and  energy  interchange  expense  increased  105% and 52% for the
three and nine months ended September 30, 1998 compared to 1997. The increase in
fuel and energy  interchange  was  primarily  due to an  increase in the average
price paid by the Company for purchased  power and  additional  power  purchases
associated with increased  wholesale  electric sales. The increase was partially
offset by the return to service of Salem,  which  decreased the need to purchase
power to replace the output from these units.

OPERATING AND MAINTENANCE
         Operating and maintenance expense decreased 6% and 8% for the three and
nine months  ended  September  30, 1998  compared to 1997.  The decrease for the
three and nine months was  primarily  due to lower  expenses at Salem due to the
conclusion of the outage,  reduced uncollectible  expenses and lower expenses at
nuclear- and fossil- fueled generating units and distribution system costs.

DEPRECIATION EXPENSE
         Depreciation  expense increased 7% and 8% for the three and nine months
ended September 30, 1998 compared to 1997,  primarily due to the amortization of
Deferred  Generation Costs  Recoverable in Current Rates during 1998,  preceding
the Company's transition to market-based pricing of electric generation in 1999.
Included in this  amortization  were charges that were included in Operating and
Maintenance expense and Interest Charges in 1997.

OTHER INCOME AND DEDUCTIONS
         Other  income  and  deductions  excluding  interest  charges  decreased
substantially for the three and nine months ended September 30, 1998 compared to
1997.  The decrease for the three months was primarily  due to increased  losses
from investments in subsidiaries. The decrease for the nine months was primarily
due to the second quarter 1997 settlement  reached with Public Service  Electric
and Gas Company (PSE&G) related to the shutdown of Salem and, in 1998, increased
losses from investments in subsidiaries and the second quarter  write-off of the
Company's investment in EnergyOne.

INTEREST CHARGES
         Interest  charges  decreased  9% and 3% for the three  and nine  months
ended September 30, 1998 compared to 1997.  Interest  charges  decreased for the
three months  primarily  due to the Company's  ongoing  program to reduce and/or
refinance higher cost,  long-term debt and the write-off of electric  generation
related debt  discounts at December 31, 1997.  These  decreases  were  partially
offset by lower  AFUDC  caused by fewer  projects  in AFUDC base in 1998 and the
replacement of $62 million of preferred stock with Company Obligated Mandatorily
Redeemable  Preferred  Securities of a Partnership (COMRPS) in the third quarter
of 1997.

INCOME TAXES
         Total income taxes  increased  36% and 6% for the three and nine months
ended  September 30, 1998 compared to 1997.  The increase for the three and nine
months was primarily due to higher earnings but was partially offset due to full
normalization of deferred taxes associated with deregulated generation plant.

PREFERRED STOCK DIVIDENDS
     Preferred  stock  dividends  decreased  29% and 27% for the  three and nine
months  ended  September  30,  1998  compared  to  1997,  primarily  due  to the
replacement  of $62 million of preferred  stock with COMRPS in the third quarter
of 1997.


<PAGE>
DISCUSSION OF LIQUIDITY AND CAPITAL RESOURCES
         Total  construction  expenditures,  primarily  for utility  plant,  are
estimated  to be $600  million  for 1998.  The  estimated  expenditures  include
approximately   $150  million  for  new   ventures,   principally   through  the
Telecommunications  Group. Due to the expected impact of the Final Restructuring
Order and  competition  for electric  generating  services on its future capital
resources,  the Company is currently evaluating its capital commitments for 1999
and beyond.  Certain  facilities  under  construction  and to be constructed may
require permits and licenses which the Company has no assurance will be granted.

         On October 16, 1998,  Duff & Phelps Credit Rating Company  upgraded its
ratings on the Company's first and refunding  mortgage bonds and  collateralized
medium-term  notes to "A-" from "BBB+",  hybrid  preferred  securities,  capital
trust securities and preferred stock to "BBB" from "BBB-",  and commercial paper
to "D-1" from "D-2".

         At September  30,  1998,  the Company had  outstanding  $116 million of
notes payable,  all of which were  commercial  paper. At September 30, 1998, the
Company had formal and informal lines of bank credit  aggregating  $100 million.
At September 30, 1998, the Company had no short-term investments.

         As a result of an  extraordinary  charge to earnings in December  1997,
the Company did not meet the earnings  test under the Mortgage  required for the
issuance of additional  bonds against  property  additions for the twelve months
ended  September 30, 1998. In addition,  the Company does not expect to meet the
earnings  test under the Mortgage for any  twelve-month  period  ending prior to
December 31,  1998.  At  September  30, 1998,  the Company was entitled to issue
approximately $3.9 billion of mortgage bonds against previously retired mortgage
bonds without regard to the earnings and property additions tests.

         As a result of an  extraordinary  charge to earnings in December  1997,
the Company did not meet the earnings test of the Company's Amended and Restated
Articles of  Incorporation  (Articles),  required for the issuance of additional
preferred stock without an affirmative  vote of the holders of two-thirds of all
preferred shares outstanding, for the twelve months ended September 30, 1998. In
addition,  the  Company  does not  expect to meet the  earnings  test  under the
Articles for any twelve-month period ending prior to December 31, 1998.

         For the nine months ended  September 30, 1998,  the Company's  Ratio of
Earnings to Fixed Charges (SEC Method)  (Exhibit  12-1) and Ratio of Earnings to
Combined Fixed Charges and Preferred Stock Dividends (SEC Method) (Exhibit 12-2)
were 4.43 times and 4.17  times,  respectively,  compared to 3.58 times and 3.29
times,  respectively,  in 1997.  See the 1997 Form 10-K  under  "PART I. ITEM 1.
BUSINESS-Capital Requirements and Financing Activities," for a discussion of the
ratio methods.

         As previously  disclosed,  the Company's Board of Directors  authorized
the  repurchase of up to 25 million shares of its common stock from time to time
through open market,  privately negotiated and/or other types of transactions in
conformity with the rules of the Securities and Exchange Commission (SEC).

         The Company has entered into forward purchase  agreements to be settled
from time to time, at the Company's election, on either a physical, net share or
net cash basis. The amount at which these agreements can be settled is dependent
principally  upon the market price of the Company's  common stock as compared to
the forward purchase price per share and the number of shares to be settled.  If
these  agreements  had been settled on a net share basis at September  30, 1998,
based on the  closing  price of the  Company's  common  stock on that date,  the
Company would have received  approximately  3,624,000  shares of Company  common
stock.
<PAGE>
YEAR 2000 PROJECT
         The  Company's  Year 2000 Project  (Project) is proceeding on schedule.
The Project is addressing the issue  resulting from computer  programs using two
digits  rather  than four to define the  applicable  year and other  programming
techniques  that  constrain  date  calculations  or assign  special  meanings to
certain  dates (Y2K  Issue).  Any of the  Company's  computer  systems that have
date-sensitive  software or  microprocessors  may recognize a date using "00" as
the year 1900 rather than the year 2000.  This could result in a system  failure
or miscalculations  causing  disruptions of operations,  including,  among other
things,  a temporary  inability  to process  transactions,  send bills,  operate
generation stations, or engage in similar normal business activities.

         The  Company  has  determined  that it will be  required  to  modify or
replace significant portions of its software and embedded technology so that its
computer  systems will  properly  utilize  dates beyond  December 31, 1999.  The
Company  presently  believes  that  with  modifications  to  existing  software,
conversions to new software, and replacement of embedded technology,  the effect
of the Y2K Issue on the  Company can be  mitigated.  If such  modifications  and
conversions are not made, or are not completed in a timely manner, the Y2K Issue
could have a material  impact on the operations  and financial  condition of the
Company. The costs associated with this potential impact are speculative and not
presently quantifiable.

         The Company is  utilizing  both  internal  and  external  resources  to
reprogram,  or replace,  and test software and computer systems for the Project.
The  Project  is  scheduled  for   completion  by  June  1,  1999,   except  for
modifications,  conversions or  replacements  that are being  incorporated  into
scheduled plant outages between June and December 1999.

The Project
         The  Project  is  divided  into  four  major   sections  -  Information
Technology Systems (IT Systems),  Embedded  Technology (devices used to control,
monitor or assist the operation of equipment,  machinery or plant), Supply Chain
(third-party  suppliers and customers),  and Contingency  Planning.  The general
phases  common to all  sections  are:  (1)  inventorying  Year 2000  items;  (2)
assigning  priorities to identified items; (3) assessing the Year 2000 readiness
of items determined to be material to the Company; (4) converting material items
that are determined not to be Year 2000 ready;  (5) testing  material items; and
(6)  designing and  implementing  contingency  plans for each  critical  Company
process.  Material  items  are  those  believed  by the  Company  to have a risk
involving  the  safety of  individuals,  may cause  damage  to  property  or the
environment, or affect revenues.

         The IT Systems  section  includes both the  conversion of  applications
software  that is not Year  2000  ready and the  replacement  of  software  when
available from the supplier.  The Company estimates that the software conversion
phase was  approximately  48% complete at September 30, 1998,  and the remaining
conversions  are on schedule  to be tested and  completed  by June 1, 1999.  The
Company  estimates that  replacements and upgrades will be completed on schedule
by June 1, 1999,  although some vendor  software  replacements  and upgrades are
behind  schedule.  Contingency  planning  for  IT  Systems  is  scheduled  to be
completed by June 1, 1999.  The Project has  identified 343 critical IT Systems.
The current readiness status of those systems is set forth below:

Number of Systems          Progress Status
-----------------          -------------------------------------------------
26 Systems                 Year 2000 Ready
87 Systems                 In Testing
191 Systems                In Active Code Modification, Or Package Upgrading
39 Systems                 Scheduled to Start after September 30, 1998
<PAGE>
         The  Embedded  Technology  section  consists  of  hardware  and systems
software  other  than IT  Systems.  The  Company  estimates  that  the  Embedded
Technology section was approximately 61% complete at September 30, 1998, and the
remaining  conversions  are on  schedule to be tested and  completed  by June 1,
1999.  Contingency planning for Embedded Technology is scheduled to be completed
by June 1, 1999.  The Project has identified  119 critical  Embedded  Technology
systems. The current readiness status of those systems is set forth below:

Number of Systems                           Progress Status
-----------------                           -------------------
25 Systems                                  Year 2000 Ready
94 Systems                                  In Active Upgrading

         The Supply  Chain  section  includes  the  process of  identifying  and
prioritizing  critical suppliers and critical customers with common equipment at
the direct interface level,  and  communicating  with them about their plans and
progress  in   addressing   the  Y2K  Issue.   The  Company   initiated   formal
communications  with all of its critical  suppliers  and  critical  customers to
determine  the extent to which the Company may be  vulnerable to their Year 2000
issues.  The  process  of  evaluating  these  critical  suppliers  and  critical
customers has commenced and is scheduled to be completed by June 1, 1999.

Costs
         The estimated total cost of the Project is $75.4 million,  the majority
of which will be incurred during testing.  This estimate  includes the Company's
share of Year 2000 costs for jointly owned facilities. The total amount expended
on the Project through September 30, 1998 was $7.3 million.  The Company expects
to fund the Project  from  operating  cash flows.  The  Company's  current  cost
estimate for the Project is set forth below:

                                        $ Millions
                  1998              1999             2000              Total
                  -----             -----            -----             -----
O&M               22.3              37.5              9.3              69.1
Capital            1.4               4.9               -                6.3
                  -----             -----            -----             -----
Total             23.7              42.4              9.3              75.4

Risks
         The  Company's  failure to become  Year 2000 ready  could  result in an
interruption  in  or  a  failure  of  certain  normal  business   activities  or
operations.  In addition,  there can be no  assurance  that the systems of other
companies on which the  Company's  systems  rely or with which they  communicate
will be timely converted,  or that a failure to convert by another company, or a
conversion  that is  incompatible  with the Company's  systems,  will not have a
material  adverse  effect on the Company.  Such failures  could  materially  and
adversely  affect the Company's  results of operations,  liquidity and financial
condition.  The Company is currently developing contingency plans to address how
to respond to events that may disrupt  normal  operations  including  activities
with PJM Interconnection, L.L.C.

         The costs of the  Project  and the date on which the  Company  plans to
complete the Year 2000 modifications are based on estimates,  which were derived
utilizing  numerous   assumptions  of  future  events  including  the  continued
availability  of certain  resources,  third-party  modification  plans and other
factors.  However,  there  can be no  assurance  that  these  estimates  will be
achieved. Actual results could differ materially from the projections.  Specific
factors that might cause a material change include,  but are not limited to, the
availability  and cost of personnel  trained in this area, the ability to locate
and correct all  relevant  computer  programs and  microprocessors,  and similar
uncertainties.
<PAGE>
         The Project is expected to significantly  reduce the Company's level of
uncertainty about the Y2K Issue. The Company believes that the completion of the
Project as scheduled  reduces the  possibility of significant  interruptions  of
normal operations.

FORWARD-LOOKING STATEMENTS
         Except for the historical  information contained herein, certain of the
matters  discussed  in this  Report  are  forward-looking  statements  which are
subject to risks and uncertainties.  The factors that could cause actual results
to differ  materially  include those discussed herein as well as those listed in
notes 2, 3 and 7 of Notes to Condensed  Consolidated  Financial  Statements  and
other  factors  discussed in the  Company's  filings  with the SEC.  Readers are
cautioned not to place undue reliance on these forward-looking statements, which
speak only as of the date of this Report.  The Company  undertakes no obligation
to publicly release any revision to these forward-looking  statements to reflect
events or circumstances after the date of this Report.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
         None.

<PAGE>
                           PART II - OTHER INFORMATION

ITEM 1.  LEGAL PROCEEDINGS
         As previously reported in the March 31, 1998 Form 10-Q, the Grays Ferry
Cogeneration  Partnership  sued the  Company  in the  Court of  Common  Pleas in
Philadelphia County (Common Pleas Court) to enjoin the Company's  termination of
the power purchase agreements  relating to the Grays Ferry Cogeneration  Project
(Grays Ferry Project).

         In a separate action,  on March 18, 1998, Chase Manhattan Bank (Chase),
the lender for the Grays  Ferry  Project,  filed an action in the United  States
District  Court for the  Eastern  District of  Pennsylvania  against the Company
alleging  breach of the letter  agreement  relating to the Grays Ferry Project's
credit.  On August 10, 1998,  Chase  voluntarily  dismissed its suit against the
Company. On August 21, 1998, Chase intervened as a plaintiff in the Common Pleas
Court action.

ITEM 5.  OTHER INFORMATION
         As  previously  reported in the June 30, 1998 Form 10-Q,  an intervenor
brought an action  asserting  that the  Competition  Act  violated  the Commerce
Clause of United States Constitution.  On May 7, 1998, the Commonwealth Court of
Pennsylvania (Commonwealth Court) unanimously rejected the claim. The intervenor
petitioned the Supreme Court of Pennsylvania  for allowance of an appeal,  which
petition was denied on September 29, 1998. The intervenor has until December 28,
1998 to file a petition for certiorari with the United States Supreme Court.

         As previously reported in the 1997 Form 10-K, two original jurisdiction
actions were filed in the  Pennsylvania  Commonwealth  Court  claiming  that the
manner in which the Competition Act was passed by the  Pennsylvania  legislature
violated the Pennsylvania Constitution. On September 24, 1998, those claims were
rejected by the  Commonwealth  Court. On October 26, 1998, the appeal period for
those  cases  expired  without  any party  filing an appeal to the  Pennsylvania
Supreme Court.

     On  September  21,  1998,  the PUC  entered an Order  directing  holders of
installed  capacity  resources  in PJM  Interconnection  L.L.C.  (including  the
Company) to immediately  release/offer the capacity for sale at wholesale during
1999 at a presumptive price of $19.72 per  kilowatt-year,  a price below current
competitive  wholesale  market prices.  On October 21, 1998, the Company filed a
Petition for Review of the PUC Order in Commonwealth Court seeking a declaration
that the PUC's Order is preempted because it attempts to regulate matters within
the exclusive federal jurisdiction of the Federal Energy Regulatory  Commission.
On October 28, 1998,  the Company  entered into a settlement  with the PUC under
which the Company agreed to make certain of its wholesale  capacity available to
new market entrants serving retail load within the Company's  service  territory
at  specified  prices  during 1999.  On October 30,  1998,  the PUC approved the
settlement.

         On  September  16,  1998,  the NRC  suspended  its SALP  program for an
interim period until the NRC staff completes a review of its nuclear power plant
performance assessment process. During the interim period while the SALP program
is suspended,  the NRC will utilize the results of its plant performance reviews
to provide nuclear power plant performance  information to licensees,  state and
local  officials  and  the  public.  These  reviews  are  intended  to  identify
performance  trends  since  the  previous  assessment  and make any  appropriate
changes to the NRC's inspection  plans. At the end of the process,  the NRC will
decide whether to resume the SALP program or substitute an alternative program.

         As  previously  reported  in the 1997 Form 10-K and the March 31,  1998
Form  10-Q,  the NRC  issued a  Bulletin  proposing  the  installation  of large
capacity passive  strainers to resolve the problem of clogging of emergency core
cooling system suction strainers  experienced at some GE Boiling Water Reactors.
Strainers  are  scheduled to be  installed at Unit No. 2 at Peach Bottom  Atomic
Power Station (Peach Bottom) during its October-November 1998 refueling outage.
<PAGE>
         As previously reported in the June 30, 1998 Form 10-Q, the NRC issued a
confirmatory  order modifying the license for Peach Bottom Units No. 2 and No. 3
requiring that the Company complete final  implementation of corrective  actions
on the Thermo-Lag  330 issue by completion of the October 1999 refueling  outage
of Peach Bottom Unit No. 3. In  addition,  the NRC issued a  confirmatory  order
modifying the license for Limerick Generating Station (Limerick) Units No. 1 and
No. 2 requiring  that the Company  complete final  implementation  of corrective
actions on the  Thermo-Lag  330 issue by completion of the April 1999  refueling
outage of Limerick Unit No. 2.

         The Company has been  informed by PSE&G that,  in  connection  with the
NRC's  generic  letter  regarding  Year 2000  issues,  on July 23,  1998,  PSE&G
provided its written  response to the NRC  outlining  its Nuclear  Business Unit
(NBU) Year 2000 program and indicating  that planned  implementation  will allow
the NBU to be Year 2000 ready and in compliance with the terms and conditions of
its licenses and NRC  regulation  by January 1, 2000.  As of September 30, 1998,
PSE&G's NBU Year 2000  effort is on schedule to meet the July 1999 NRC  response
schedule.

         The Company has been informed by PSE&G that, on September 15, 1998, the
NRC issued its latest Systematic  Assessment of Licensee  Performance (SALP) for
Salem  for the  period  March  1,  1997 to  August  1,  1998.  In the  areas  of
Maintenance and Engineering,  Salem was rated Category 2 or "good." In the areas
of Operations and Plant Support,  Salem was rated Category 1 or "superior."  The
NRC noted improved performance overall during the period, as demonstrated by the
nearly  event-free  return of both units to  operation  following  the  extended
outage.  The NRC identified strong management  oversight,  safe and conservative
operations,  good  engineering  support and effective  programs for  independent
oversight  and   self-assessment.   The  NRC  also  noted  that  although  human
performance has improved significantly due to extensive training  interventions,
continued  close  management  attention  is  warranted  in  the  Operations  and
Maintenance areas.

         The Company has been  informed by PSE&G that,  as part of an inspection
by the NRC in April  1997,  the NRC noted  certain  weaknesses  in PSE&G's  fire
barrier  systems.  PSE&G sent a letter to the NRC in June 1997 addressing  these
issues  concerning  the  qualification  of fire wrap  barriers  used to  protect
electrical  cabling at Salem. The letter outlined a resolution plan and schedule
to address the fire wrap issues.  PSE&G had committed to alternative measures in
the form of fire  watches  until  this  plan is  implemented.  A  review  of the
installed  fire barrier  materials  and safe  shutdown  analysis is currently in
progress. If certain modifications are mandated by the NRC, this could result in
a material  adverse  impact to the  Company's  financial  condition,  results of
operations  and net cash flows.  Additionally,  failure to  resolved  these fire
barrier  issues  could result in potential  NRC  violations,  fines and/or plant
shutdown.

         As previously  reported in the 1997 Form 10-K,  the NRC had proposed to
issue a generic  letter  which  would  require all nuclear  plant  operators  to
provide the NRC with information concerning the operators' programs,  planned or
implemented,  to address Year 2000 computer and system issues at its facilities.
On May 11, 1998, the NRC issued a Generic  Letter  requiring (1) submission of a
written response within 90 days, indicating whether the operator has pursued and
continues to pursue  implementation  of Year 2000  programs and  addressing  the
program's  scope,  assessment  process,  plans for corrective  actions,  quality
assurance  measures,  contingency  plans  and  regulatory  compliance,  and  (2)
submission of a written  response,  no later than July 1, 1999,  confirming that
such  facilities  are Year 2000 ready,  or will be Year 2000 ready,  by the year
2000 with regard to compliance  with the terms and  conditions of the license(s)
and NRC  regulations.  On July 30, 1998,  the Company filed its 90-day  required
written  response  indicating  that the Company has pursued and is continuing to
pursue a Year 2000 program which is similar to that outlined in Nuclear  Utility
Year 2000 Readiness, NEI/NUSMG 97-07.
<PAGE>
         An Order was entered on July 17, 1998, by the PUC, instituting a formal
investigation by the Office of Administrative  Law Judge on Year 2000 compliance
by jurisdictional fixed utilities and mission-critical service providers such as
the PJM Interconnection. The Order requires, (1) a written response to a list of
compliance program questions by August 6, 1998 and, (2) all jurisdictional fixed
utilities be Year 2000  compliant by March 31, 1999 or, if a utility  determines
that  mission-critical  systems cannot be Year 2000 compliant on or before March
31, 1999, the utility is required to file a detailed  contingency  plan. The PUC
adopted the federal government's definition for Year 2000 compliance and further
defined  Year  2000   compliance  as  a   jurisdictional   utility   having  all
mission-critical  Year 2000 hardware and software  updates  and/or  replacements
installed and tested on or before March 31, 1999. On August 6, 1998, the Company
filed  its  written  response,  in which  the  Company  stated  that  with a few
carefully-assessed  and  closely-managed  exceptions,  the Company will have all
mission-critical  systems Year 2000 ready by June 1999.  The Company also stated
that it was in the process of developing Year 2000 contingency plans.

         On  September  24,  1998,  the EPA  announced  the  issuance of a final
regulation  which will  require 22 states and the District of Columbia to reduce
emissions of nitrogen oxides (NOx) by more than 1 million tons annually  between
2003 and 2007.  The main goal of the  regulation  is to limit the  transport  of
ozone  pollution  into  the  northeastern  states,  including  Pennsylvania,  by
reducing  NOx  emissions  in  southern  and  midwestern   states.   Pennsylvania
utilities,  including  the Company,  are already  subject to strict NOx emission
limits.  A group of southern  and  midwestern  utilities  have  announced  their
intention of appealing  the issuance of the EPA  regulation to the Federal Court
of Appeals.

         As  previously  reported  in the  1997  Form  10-K,  the  Environmental
Protection Agency (EPA) sent letters to approximately 20 potentially responsible
parties (PRPs), including the Company, giving them 60 days to negotiate with the
EPA to perform the proposed  remedy for the Metal Bank of America site  outlined
in the EPA's December 1997 record of decision (ROD). The Company, along with the
nine  other PRPs in the  utility  PRP group,  responded  to the EPA's  letter by
offering to conduct the Remedial  Design (RD) but not the  Remedial  Action (RA)
outlined in the ROD.  The EPA  rejected  the PRP group's  offer and, on June 26,
1998,  issued an Order to the non-de  minimis  PRP Group  members,  and  others,
including the owner,  to implement the RD and RA. The PRP Group is proceeding as
required by the Order;  it has selected a contractor  which has been approved by
the EPA, and is preparing the RD Work Plan.

         As previously  reported in the 1997 Form 10-K, the Company was added as
a  third-party  defendant  in an  existing  suit  alleging  that the  Company is
responsible  for sending  waste to the  Cinnaminson  Ground Water  Contamination
Site.  On  June  4,  1998,  the  Company  entered  into a  settlement  with  the
defendants.
<PAGE>
ITEM 6.  EXHIBITS AND REPORTS ON FORM 8-K
(a)      Exhibits:

         12-1     -        Statement regarding computation of ratio of
                           earnings to fixed charges.
         12-2     -        Statement regarding computation of ratio of
                           earnings to combined fixed charges and preferred
                           stock dividends.
         27       -        Financial Data Schedule.

(b)      Reports on Form 8-K filed during the reporting period:

         Report,  dated July 17, 1998 reporting information under "ITEM 5. OTHER
                  EVENTS"  regarding  AmerGen  Energy  Company,  LLC,  the joint
                  venture  between the Company and British Energy plc,  entering
                  into a Letter of Intent to purchase Three Mile Island Unit No.
                  1 from GPU, Inc.

         Reports on Form 8-K filed subsequent to the reporting period:
         Report,  dated October 15, 1998  reporting  information  under "ITEM 5.
                  OTHER EVENTS" regarding AmerGen Energy Company, LLC, the joint
                  venture between the Company and British Energy plc,  signing a
                  definitive  asset  purchase  agreement to purchase  Three Mile
                  Island Unit No. 1 from GPU, Inc.



<PAGE>



                                   Signatures

         Pursuant to  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.




                                                           PECO ENERGY COMPANY
                                                        /s/ Michael J. Egan
                                                      --------------------------
                                                            MICHAEL J. EGAN
                                                       Senior Vice President and
                                                        Chief Financial Officer
                                                        (Principal Financial and
                                                          Accounting Officer)

Date:  October 30, 1998