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 June 30, 1999

                                       OR

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

                         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  186,603,406  shares of common  stock  outstanding  on
         August 6, 1999.

<PAGE>
PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

                  PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
                   CONDENSED CONSOLIDATED STATEMENTS OF INCOME
                                   (Unaudited)
                  (Millions of Dollars, Except Per Share Data)

<TABLE>
<CAPTION>
                                                         Three Months Ended June 30,         Six Months Ended June 30,
                                                           1999              1998             1999             1998
                                                        -----------      -----------     ------------     ------------
OPERATING REVENUES
<S>                                                     <C>                  <C>              <C>              <C>
     Electric                                           $   1,105.4          1,131.8          2,144.3          2,134.8
     Gas                                                       89.0             83.4            306.5            270.6
                                                        -----------      -----------     ------------     ------------
TOTAL OPERATING REVENUES                                    1,194.4          1,215.2          2,450.8          2,405.4
                                                        -----------      -----------     ------------     ------------
OPERATING EXPENSES
     Fuel and Energy Interchange                              500.3            360.2            965.4            743.2
     Operating and Maintenance                                338.9            256.0            627.6            539.2
     Depreciation and Amortization                             57.6            160.9            113.9            315.6
     Taxes Other Than Income                                   45.2             71.8            120.5            153.9
                                                        -----------      -----------     ------------     ------------
                                                              942.0            848.9          1,827.4          1,751.9
                                                        -----------      -----------     ------------     ------------
OPERATING INCOME                                              252.4            366.3            623.4            653.5
                                                        -----------      -----------     ------------     ------------

OTHER INCOME AND DEDUCTIONS
     Interest Expense                                        (113.5)           (86.0)          (187.8)          (171.0)
     Company Obligated Mandatorily Redeemable
          Preferred Securities of a Partnership                (7.4)            (8.2)           (14.8)           (15.9)
     Allowance for Funds Used During Construction               1.7              0.7              2.1              1.3
     Other, Net                                                (4.6)           (26.9)           (46.6)           (39.7)
                                                        -----------      -----------     ------------     ------------

TOTAL OTHER INCOME AND DEDUCTIONS                            (123.8)          (120.4)          (247.1)          (225.3)
                                                        -----------      -----------     ------------     ------------

INCOME BEFORE INCOME TAXES AND
   EXTRAORDINARY ITEM                                         128.6            245.9            376.3            428.2

INCOME TAXES                                                   41.0             94.4            139.0            163.1
                                                        -----------      -----------     ------------     ------------

INCOME BEFORE EXTRAORDINARY ITEM                               87.6            151.5            237.3            265.1

EXTRAORDINARY ITEM - NET OF INCOME TAXES                      (26.7)            --              (26.7)            --
                                                        -----------      -----------     ------------     ------------

NET INCOME                                                     60.9            151.5            210.6            265.1

PREFERRED STOCK DIVIDENDS                                       3.3              3.3              6.6              6.6
                                                        -----------      -----------     ------------     ------------

EARNINGS APPLICABLE TO COMMON STOCK                     $      57.6      $     148.2      $     204.0      $     258.5
                                                        ===========      ===========     ============     ============

AVERAGE SHARES OF COMMON STOCK
     OUTSTANDING (Millions)                                   192.0            222.7            207.6            222.6
                                                        ===========      ===========     ============     ============

BASIC AND DILUTIVE EARNINGS PER
AVERAGE COMMON SHARES BEFORE EXTRAORDINARY ITEM         $      0.44      $      0.66     $       1.11     $       1.16
EXTRAORDINARY ITEM                                            (0.14)            --              (0.13)            --
                                                        -----------      -----------     ------------     ------------
BASIC EARNINGS PER AVERAGE COMMON SHARE                 $      0.30      $      0.66     $       0.98     $       1.16
                                                        ===========      ===========     ============     ============

DIVIDENDS PER AVERAGE COMMON SHARE                      $      0.25      $      0.25     $       0.50     $       0.50
                                                        ===========      ===========     ============     ============
</TABLE>

See Notes to Condensed Consolidated Financial Statements.


                                       2
<PAGE>
                  PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
                      CONDENSED CONSOLIDATED BALANCE SHEETS
                              (Millions of Dollars)

<TABLE>
<CAPTION>
                                                                             June 30,           December 31,
                                                                               1999                1998
                                                                            ----------          ----------
                                                                           (Unaudited)
ASSETS

UTILITY PLANT
<S>                                                                        <C>                 <C>
Electric - Transmission & Distribution                                     $   3,890.8         $   3,833.8
Electric - Generation                                                          1,732.3             1,713.4
Gas                                                                            1,141.2             1,132.0
Common                                                                           409.3               407.3
                                                                            ----------          ----------

                                                                               7,173.6             7,086.5
Less Accumulated Provision for Depreciation                                    3,007.6             2,891.3
                                                                            ----------          ----------

                                                                               4,166.0             4,195.2
Nuclear Fuel, net                                                                296.7               141.9
Construction Work in Progress                                                    375.0               272.6
Leased Property, net                                                               0.5               154.3
                                                                            ----------          ----------

                                                                               4,838.2             4,764.0
                                                                            ----------          ----------


CURRENT ASSETS
Cash and Temporary Cash Investments                                              899.6                48.1
Accounts Receivable, net
     Customer                                                                    213.1                97.5
     Other                                                                       376.2               213.2
Inventories, at average cost
     Fossil Fuel                                                                  62.9                92.3
     Materials and Supplies                                                      108.8                82.1
Deferred Income Taxes                                                              7.7               (14.1)
Other                                                                            109.0                19.0
                                                                            ----------          ----------

                                                                               1,777.3               538.1
                                                                            ----------          ----------

DEFERRED DEBITS AND OTHER ASSETS
Competitive Transition Charge                                                  5,274.6             5,274.6
Recoverable Deferred Income Taxes                                                609.2               614.4
Deferred Non-Pension Postretirement Benefits Costs                                87.7                90.9
Investments                                                                      554.8               538.1
Loss on Reacquired Debt                                                           73.9                77.2
Other                                                                            131.0               107.1
                                                                            ----------          ----------

                                                                               6,731.2             6,702.3
                                                                            ----------          ----------

TOTAL                                                                       $ 13,346.7          $ 12,004.4
                                                                            ==========          ==========
</TABLE>

            See Notes to Condensed Consolidated Financial Statements.
                            (continued on next page)

                                       3
<PAGE>
                  PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
                      CONDENSED CONSOLIDATED BALANCE SHEETS
                              (Millions of Dollars)
                                   (continued)
<TABLE>
<CAPTION>
                                                                            June 30,          December 31,
                                                                              1999                1998
                                                                            ----------          ----------
                                                                           (Unaudited)
CAPITALIZATION AND LIABILITIES

CAPITALIZATION
Common Shareholders' Equity
<S>                                                                       <C>                 <C>
     Common Stock (No Par)                                                $    3,616.7        $    3,589.0
     Other Paid-In Capital                                                         1.2                 1.2
     Accumulated Deficit                                                        (422.5)             (532.9)
     Treasury Stock                                                           (1,507.3)                 --
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                                       340.4               349.4
Long-Term Debt                                                                 6,092.2             2,919.6
                                                                            ----------          ----------

                                                                               8,350.9             6,556.5
                                                                            ----------          ----------

CURRENT LIABILITIES
Notes Payable, Bank                                                              226.0               525.0
Long-Term Debt Due Within One Year                                               146.1               361.5
Capital Lease Obligations Due Within One Year                                     --                  69.0
Accounts Payable                                                                 357.5               316.2
Taxes Accrued                                                                    187.4               170.5
Interest Accrued                                                                 104.9                61.5
Deferred Energy Costs - Gas                                                       26.3               (29.9)
Other                                                                            235.6               217.4
                                                                            ----------          ----------

                                                                               1,283.8             1,691.2
                                                                            ----------          ----------

DEFERRED CREDITS AND OTHER LIABILITIES
Capital Lease Obligations                                                          0.5                85.3
Deferred Income Taxes                                                          2,355.3             2,376.9
Unamortized Investment Tax Credits                                               292.8               300.0
Pension Obligation                                                               219.3               219.3
Non-Pension Postretirement Benefits Obligation                                   436.1               421.1
Other                                                                            408.0               354.1
                                                                            ----------          ----------

                                                                               3,712.0             3,756.7
                                                                            ----------          ----------

COMMITMENTS AND CONTINGENCIES (NOTE 8)

TOTAL                                                                      $  13,346.7          $ 12,004.4
                                                                           ===========          ==========
</TABLE>

            See Notes to Condensed Consolidated Financial Statements.

                                       4
<PAGE>
                  PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
                 CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
                                   (Unaudited)
                              (Millions of Dollars)
<TABLE>
<CAPTION>
                                                                     Six Months Ended June 30,
                                                                       1999             1998
                                                                   ----------         --------
CASH FLOWS FROM OPERATING ACTIVITIES
<S>                                                                <C>                <C>
NET INCOME                                                         $    210.6         $  265.1
EXTRAORDINARY ITEM, NET OF INCOME TAXES                                  26.7             --
                                                                   ----------         --------

INCOME BEFORE EXTRAORDINARY ITEM                                        237.3            265.1

Adjustments to Reconcile Net Income to Net Cash
     Provided by Operating Activities:
Depreciation and Amortization                                           149.4            343.0
Deferred Income Taxes                                                   (38.2)           (29.3)
Amortization of Investment Tax Credits                                   (7.2)            (9.0)
Deferred Energy Costs                                                    56.1             27.1
Changes in Working Capital:
     Accounts Receivable                                               (278.5)           (87.1)
     Inventories                                                          2.7              9.0
     Accounts Payable                                                    41.3            (11.3)
     Other Current Assets and Liabilities                                14.4            (68.8)
Other Items Affecting Operations                                         74.4             71.3
                                                                   ----------         --------


CASH FLOWS PROVIDED BY OPERATING ACTIVITIES                             251.7            510.0
                                                                   ----------         --------


CASH FLOWS FROM INVESTING ACTIVITIES

Investment in Plant                                                    (244.4)          (229.1)
Increase in Investments                                                 (35.0)           (35.8)
                                                                   ----------         --------


NET CASH FLOWS USED IN INVESTING ACTIVITIES                            (279.4)          (264.9)
                                                                   ----------         --------


CASH FLOWS FROM FINANCING ACTIVITIES

Issuance of Long-Term Debt                                            4,000.0              6.4
Common Stock Repurchase                                              (1,507.3)            --
Debt Repayments                                                      (1,202.5)           (96.8)
Change in Short-Term Debt                                              (299.0)           (55.5)
Dividends on Preferred and Common Stock                                (109.9)          (117.8)
Issuance of Company Obligated Mandatorily
     Redeemable Preferred Securities of a Partnership                    --               78.1
Issuance of Common Stock                                                 14.0              9.3
Other Items Affecting Financing                                         (16.1)             3.1
                                                                   ----------         --------


NET CASH FLOWS PROVIDED BY (USED IN) FINANCING ACTIVITIES               879.2           (173.2)
                                                                   ----------         --------


INCREASE IN CASH AND CASH EQUIVALENTS                                   851.5             71.9
                                                                   ----------         --------


CASH AND CASH EQUIVALENTS AT BEGINNING OF  PERIOD                        48.1             33.4
                                                                   ----------         --------


CASH AND CASH EQUIVALENTS AT END OF  PERIOD                        $    899.6         $  105.3
                                                                   ==========         ========
</TABLE>

            See Notes to Condensed Consolidated Financial Statements.

                                       5
<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 June
30, 1999 and for the three and six 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
1998 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, 1998.


2.       TRANSITION BONDS
         On March 25, 1999, PECO Energy  Transition Trust (PETT), an independent
statutory business trust organized under the laws of Delaware and a wholly owned
subsidiary  of the  Company,  issued $4 billion  aggregate  principal  amount of
Transition  Bonds  (Transition  Bonds) to  securitize a portion of the Company's
authorized  stranded cost recovery.  The Transition Bonds are solely obligations
of PETT, secured by Intangible  Transition  Property sold by the Company to PETT
concurrently  with the  issuance  of the  Transition  Bonds  and  certain  other
collateral related thereto.

         The terms of the Transition Bonds are as follows:
<TABLE>
<CAPTION>
                       Approximate
                       Face Amount          Bond            Expected                   Final
         Class         (millions)           Rates           Maturity                   Maturity
<S>                   <C>                  <C>              <C>                      <C>
         A-1           $244.5               5.48%           March 1, 2001              March 1, 2003
         A-2           $275.4               5.63%           March 1, 2003              March 1, 2005
         A-3           $667.0               5.18% (a)       March 1, 2004              March 1, 2006
         A-4           $458.5               5.80%           March 1, 2005              March 1, 2007
         A-5           $464.6               5.26% (a)       September 1, 2007          March 1, 2009
         A-6           $993.4               6.05%           March 1, 2007              March 1, 2009
         A-7           $896.7               6.13%           September 1, 2008          March 1, 2009
</TABLE>

         (a) The Class A-3 and A-5 Transition  Bonds earn interest at a floating
         rate.  The rates  provided for each such class above are as of June 30,
         1999.


                                       6
<PAGE>


         The  Company  entered  into  treasury  forwards  and  forward  starting
interest  rate  swaps to  manage  interest  rate  exposure  associated  with the
anticipated  issuance of Transition  Bonds. On March 18, 1999, these instruments
were settled with net proceeds to the Company of approximately $80 million which
were deferred and are being amortized over the life of the Transition Bonds as a
reduction of interest  expense,  consistent with the Company's hedge  accounting
policy.

         The Company has entered  into  interest  rate swaps to manage  interest
rate  exposure  associated  with the  issuance  of two  floating  rate series of
Transition  Bonds. At June 30, 1999, the fair value of these instruments was $52
million based on the present value difference between the contracted rate (i.e.,
hedged rate) and the market rates at that date.  A  hypothetical  50 basis point
increase or  decrease in the spot yield at June 30, 1999 would have  resulted in
an aggregate  fair value of these  interest rate swaps of $91.2 million or $10.7
million, respectively. If the derivative instruments had been terminated at June
30, 1999,  these  estimated  fair values  represent the amount to be paid by the
counterparties to the Company.

         The net proceeds to the Company from the securitization of a portion of
its allowed  stranded cost recovery,  after payment of fees and expenses and the
capitalization of PETT, were approximately $3.95 billion. In accordance with the
provisions  of the  Pennsylvania  Electricity  Generation  Customer  Choice  and
Competition  Act, the Company is utilizing these proceeds  principally to reduce
its  stranded  costs and related  capitalization.  Through  June 30,  1999,  the
Company  utilized the net proceeds to repurchase  38.7 million  shares of Common
Stock for an aggregate purchase price of $1.507 billion; to retire: $811 million
of First Mortgage  Bonds,  a $400 million term loan,  $208 million of commercial
paper, $150 million of accounts receivable  financing and a $139 million capital
lease  obligation;  to  repurchase $9 million of Company  Obligated  Mandatorily
Redeemable  Preferred  Securities  of a  Partnership  (COMRPS);  and to pay  $25
million of debt issuance costs.  The remaining  proceeds of  approximately  $750
million are  included in cash at June 30, 1999.  In addition,  on July 30, 1999,
the Company  redeemed  $212  million of COMRPS.  On August 2, 1999,  the Company
retired $37 million of Mandatorily  Redeemable  Preferred  Stock pursuant to the
sinking fund requirements of those securities.

         In the second  quarter of 1999, the Company  incurred an  extraordinary
charge of $26.7 million,  net of tax,  consisting of prepayment premiums and the
write-off of unamortized  deferred  financing  costs  associated  with the early
retirement of debt.


3.   SEGMENT INFORMATION
         The Company is primarily a vertically  integrated  public  utility that
provides  retail  electric  and  natural  gas  service  to  the  public  in  its
traditional  service territory and retail electric generation service throughout
Pennsylvania  pursuant to Pennsylvania's  Customer Choice Program. The Company's
management  has  historically  managed  the Company as a  vertically  integrated
entity by analyzing its results of operations  on a  consolidated  basis with an
emphasis on electric and gas operations.

          During the first quarter of 1999,  the Company  completed the redesign
of its internal  reporting  structure to separate its distribution,  generation,


                                       7
<PAGE>

and  ventures   operations  into  business  units  and  provide   financial  and
operational  data  on  the  same  basis  to  senior  management.  The  Company's
distribution  business unit includes its electric  transmission and distribution
services,   regulated  retail  sales  of  generation  services  and  retail  gas
businesses. The Company's generation business unit includes the operation of its
generation assets and its power marketing group. The Company's ventures business
unit includes its unregulated  retail energy supplier,  infrastructure  services
business and its telecommunications equity investments.

         During the second  quarter of 1999,  the  Company  further  revised the
internal  reporting  structure to include its unregulated retail energy supplier
with the  generation  business  unit to more  efficiently  manage the  Company's
overall energy supply requirements.  Accordingly,  the results of operations and
assets of the unregulated  retail energy supplier are included in the generation
business unit for all periods presented.

         The  Company's  segment  information  as of and for the  three  and six
months ended June 30, 1999 as compared to the same 1998 period is as follows (in
millions of dollars):

Quarter Ended June 30, 1999 as compared to the quarter ended June 30, 1998
<TABLE>
<CAPTION>
<S>                 <C>                 <C>                 <C>            <C>              <C>                <C>
                                                                                            Intersegment
                    Distribution        Generation         Ventures       Corporate           Revenues         Consolidated
                    ------------        ----------         --------       ---------           --------         ------------
Revenues:
    1999               $734.0             $653.2             $   .6           $    -          $(193.4)           $1,194.4
    1998               $905.5             $547.7             $   .7           $    -          $(238.7)           $1,215.2
EBIT (a):
    1999               $298.2             $ 11.1            $( 15.1)         $( 44.7)                            $  249.5
    1998               $356.0             $ 61.0            $( 35.8)         $( 41.1)                            $  340.1

Six Months Ended June 30, 1999 as compared to six months ended June 30, 1998

Revenues:
    1999               $1,646.5           $1,197.9           $   1.2          $ -             $(394.8)           $2,450.8
    1998               $1,854.3           $1,029.6           $   1.3          $ -             $(479.8)           $2,405.4
EBIT (a):
    1999               $655.7             $ 41.0(b)         $( 36.0)         $( 81.8)                            $  578.9
    1998               $663.5             $ 99.0            $( 59.5)         $( 87.9)                            $  615.1
Total Assets:
    1999              $10,810.8(c)       $1,868.5            $240.2          $427.2                              $13,346.7
    1998              $ 9,723.6          $1,680.6            $216.1          $384.1                              $12,004.4
<FN>
 (a) EBIT - Earnings Before Interest and Income Taxes.
 (b) Includes an $11.8 million reserve related to the Grays Ferry power purchase
 agreement and $14.6 million related to the write-off of the investment in Grays
 Ferry in connection with the settlement of litigation.
 (c) Includes $750 million of proceeds from securitization of stranded costs.
</FN>
</TABLE>




                                       8
<PAGE>

4.       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
stock option plans,  considered  to be dilutive  common stock  equivalents.  The
following  table  shows  the  effect  of the stock  options  issuable  under the
Company's stock option plans on the average number of shares used in calculating
diluted earnings per average common share (in millions of shares):
<TABLE>
<CAPTION>
                                                            Three Months Ended                   Six Months Ended
                                                                 June 30,                             June 30,
                                                          1999                  1998            1999               1998
                                                         -----                 -----            -----             -----
<S>                                                      <C>                   <C>              <C>               <C>
Average Common Shares Outstanding                        192.0                 222.7            207.6             222.6

Assumed Conversion of Stock Options                        1.5                    .7              1.5                .7
                                                         -----                 -----            -----             -----

Potential Average Dilutive
  Common Shares Outstanding                              193.5                 223.4            209.1             223.3
                                                         =====                 =====            =====             =====
</TABLE>

5.       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 $275 million of designated  accounts  receivable  until
November 2000. At June 30, 1999, the Company had sold a $275 million interest in
accounts  receivable,   consisting  of  a  $232  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 $43 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 $275 million
interest,  which,  if not met,  requires the Company to deposit cash in order to
satisfy such requirements. The Company, at June 30, 1999, met such requirements.
At June 30, 1999, the average annual  service-charge  rate,  computed on a daily
basis on the portion of the accounts receivable sold but not yet collected,  was
4.90%.


6.       AMERGEN ENERGY COMPANY
         On April 15, 1999,  AmerGen Energy  Company,  LLC (AmerGen),  the joint
venture between the Company and British Energy, plc (British Energy),  announced
an interim  agreement to purchase the Clinton  Nuclear Power  Station  (Clinton)
from  Illinois  Power (IP), a subsidiary  of Illinova  Corporation.  On June 30,
1999,  AmerGen and British  Energy  signed a  definitive  agreement  to purchase
Clinton from IP.  AmerGen has entered  into  agreements  to purchase  Three Mile
Island Unit No.1  Nuclear  Generating  Facility,  Nine Mile Point Unit 1 Nuclear
Generating  Facility  and 59% of  Nine  Mile  Point  Unit 2  Nuclear  Generating
Facility.  In  addition,  the  Company  and IP  amended  the  January  15,  1998
Management Agreement, providing for the provision of certain management services
by the  Company  to IP in support  of  Clinton's  outage  recovery  efforts  and
operations.

                                       9
<PAGE>

   7.    CLINTON NUCLEAR POWER STATION
         Under the Amended  Management  Agreement,  effective April 1, 1999, the
Company is responsible  for the payment of all direct  operating and maintenance
(O&M)  costs and  direct  capital  costs  incurred  by IP and  allocable  to the
operation of Clinton.  IP will  continue to pay  indirect  costs such as pension
benefits,  payroll taxes and property  taxes.  Following the restart of Clinton,
which  occurred on June 2, 1999,  and through  December 31, 1999, the Company is
selling 80% of the output of Clinton to IP. The  remaining  output is being sold
by the Company in the  wholesale  market.  Under a separate  agreement  with the
Company,  British  Energy  has  agreed to share  50% of the  costs and  revenues
associated with the Amended Management Agreement. In the second quarter of 1999,
the Company  recognized  $14 million of revenue from sales to IP and $25 million
of O&M expenses related to Clinton.


8.       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, 1998.

         At June 30,  1999,  the Company had entered into  long-term  agreements
with  unaffiliated  utilities to purchase  transmission  rights.  These purchase
commitments  result in  obligations  of  approximately  $50 million in 1999, $88
million in 2000,  $51 million in 2001,  and $41 million in 2002,  $36 million in
2003 and $97 million thereafter.

         The Company has identified 28 sites where former manufactured gas plant
(MGP) activities have or may have resulted in actual site  contamination.  As of
June  30,  1999,   the  Company  had  accrued  $59  million  for   environmental
investigation and remediation costs, including $33 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 April 23, 1999, the Company and Grays Ferry Cogeneration Partnership
(Grays Ferry)  entered into a final  settlement of  litigation.  The  settlement
resulted in a restructuring of the power purchase  agreement between the Company
and Grays Ferry.  The  settlement  also required the Company to  contribute  its
interest in the partnership to the remaining partners.  Accordingly, the Company
recorded  a  charge  to  earnings  of  $14.6  million  for the  transfer  of its
partnership  interest  and a  reserve  of $11.8  million  related  to the  power
purchase agreement. The charge for the partnership interest transfer is recorded
in Other  Income  and  Deductions  and the  reserve  related  to power  purchase
agreement is recorded in Fuel and Energy  Interchange  Expense on the  Company's
Statement of Income for the six months ended June 30, 1999. The settlement  also
resolved  the  litigation  with  Westinghouse  Power  Generation  and The  Chase
Manhattan Bank.


                                       10
<PAGE>

9.       NEW ACCOUNTING PRONOUNCEMENTS
         In June 1998, the Financial  Accounting  Standards  Board (FASB) issued
SFAS No. 133,  "Accounting for Derivative  Instruments and Hedging  Activities,"
(SFAS No. 133) 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.  In June  1999,  the  FASB  issued  SFAS  No.  137  "Accounting  for
Derivative  Instruments and Hedging  Activities - Deferral of the Effective Date
of FASB  Statement No. 133," (SFAS No. 137) which delayed the effective date for
SFAS No. 133 until  fiscal  years  beginning  after June 15,  2000.  The Company
expects to adopt SFAS No. 133 in the first  quarter of 2001.  The  Company is in
the  process  of  evaluating  the  impact  of  SFAS  No.  133 on  its  financial
statements.

         In November 1998, the FASB's  Emerging  Issues Task Force (EITF) issued
EITF  98-10,  "Accounting  for  Contracts  Involved  in Energy  Trading and Risk
Management Activities." EITF 98-10 outlines attributes that may be indicative of
an energy  trading  operation and gives further  guidance on the  accounting for
contracts entered into by an energy trading operation.  This accounting guidance
requires  mark-to-market  accounting  for  contracts  considered to be a trading
activity. EITF 98-10 is applicable for fiscal years beginning after December 15,
1998 with any impact recorded as a cumulative effect adjustment through retained
earnings at the date of adoption.

         The Company's wholesale  marketing  operations enter into long-term and
short-term  commitments to purchase and sell energy and energy-related  products
with the intent and ability to deliver or take  delivery.  The  objective of the
long-term  commitments is to establish a generation base that allows the Company
to meet the  physical  supply and demand  requirements  of a national  wholesale
electric marketplace through scheduled,  real-time delivery of electricity.  The
Company utilizes  short-term energy  commitments and contracts,  entered into in
the  over-the-counter  market,  to  economically  hedge seasonal and operational
risks associated with peak demand periods and generation plant outages.

         The Company  reviewed  the  criteria  indicative  of an energy  trading
operation  as outlined in EITF 98-10  against the  objectives  and intent of the
Company's wholesale marketing operation's activities. The Company concluded that
none of the  activities of its marketing  operation are trading  activities  and
therefore  these  activities  are not  subject to EITF  98-10 or  mark-to-market
accounting.

         The Company  records  revenues and expenses  associated with the energy
commitments   at  the  time  the   underlying   physical   transaction   closes.
Additionally,  the Company evaluates its energy commitments for impairment based
on the lower of cost or market.  At June 30, 1999, the Company concluded that no
energy commitments were impaired.


                                       11
<PAGE>

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

GENERAL

         Retail   competition   for  electric   generation   services  began  in
Pennsylvania on January 1, 1999. As of January 2, 1999, two-thirds of each class
of the Company's retail electric customers in its traditional  service territory
have a right to choose their generation  suppliers.  Effective  January 2, 2000,
all of the  Company's  retail  electric  customers  in its  traditional  service
territory will have the right to choose their generation suppliers.  At June 30,
1999,   approximately  239,000  customers  representing  15%  of  the  Company's
residential customers, 25% of its commercial customers and 58% of its industrial
customers had selected an alternate  energy  supplier.  As of that date,  Exelon
Energy,  the Company's  alternative  energy  supplier,  was  providing  electric
generation service to approximately  141,000 business and residential  customers
located throughout Pennsylvania.

         Effective  January 1, 1999,  the Company  reduced  its retail  electric
rates for all customers by 8%. On that date,  the Company began  recovering  its
stranded costs through the collection of competitive transition charges from all
customers.  On March 25, 1999,  PECO Energy  Transition  Trust (PETT),  a wholly
owned  subsidiary  of the Company,  issued $4 billion of PECO Energy  Transition
Trust  Transition  Bonds to securitize a portion of the Company's  stranded cost
recovery.  In accordance with the terms of the  Competition  Act, the Company is
utilizing the proceeds from the issuance of the Transition Bonds  principally to
reduce stranded costs and capitalization.

         The Company currently  estimates that the impact of additional interest
expense  associated  with the  Transition  Bonds  partially  offset by  interest
savings  related to higher cost debt  retired  with  Transition  Bond  proceeds,
combined  with the  anticipated  reduction  in  common  equity,  will  result in
earnings  per share  benefits of  approximately  $.15 and $.50 in 1999 and 2000,
respectively.  These  estimated  earnings per share could change and are largely
dependent upon the timing and price of common stock  repurchases and anticipated
net income available to common stock.

         The Company  expects  that  competition  for both retail and  wholesale
generation services will substantially  affect its future results of operations.
See "Management's  Discussion and Analysis of Financial Condition and Results of
Operations - Outlook,"  incorporated by reference in the Company's Annual Report
on Form 10-K for the year ended December 31, 1998.

         The   Company's   internal   reporting   structure   consists   of  its
distribution,  generation,  and ventures operations.  The Company's distribution
business  unit includes its electric  transmission  and  distribution  services,
regulated  retail sales of generation  services and retail gas  businesses.  The
Company's  generation  business unit  includes the  operation of its  generation
assets,  its power marketing group and its unregulated  retail energy  supplier.
The  Company's  ventures  business  unit  includes its  infrastructure  services
business and its telecommunications equity investments.


                                       12
<PAGE>


RESULTS OF OPERATIONS

         The Company's Condensed Consolidated Statements of Income for the three
and six months ended June 30, 1998 reflect the  reclassification  of the results
of operations of Exelon Energy, from Other Income and Deductions.

         Under its  Amended  Management  Agreement  with  Illinois  Power  (IP),
effective  April 1, 1999,  the  Company is  responsible  for the  payment of all
direct  operating and maintenance  (O&M) costs and direct capital costs incurred
by IP and allocable to the operation of Clinton Nuclear Power Station (Clinton).
IP will continue to pay indirect costs such as pension  benefits,  payroll taxes
and property  taxes.  Following the restart of Clinton,  which  occurred on June
2,1999,  and through December 31, 1999, the Company is selling 80% of the output
of  Clinton  to IP. The  remaining  output is being  sold by the  Company in the
wholesale market.  Under a separate  agreement with the Company,  British Energy
has agreed to share 50% of the costs and  revenues  associated  with the Amended
Management Agreement.

<TABLE>
<CAPTION>
Revenue and Expense Items as a
Percentage of Total Operating
Revenues                                                                 Percentage Dollar Changes
                                                                               1999 vs. 1998
        Quarter           Six Months                                       Quarter        Six Months
         Ended               Ended                                          Ended           Ended
        June 30,            June 30,                                       June 30,       June 30,
    1999      1998        1999   1998
<S>  <C>       <C>         <C>    <C>                                        <C>           <C>
     93%       93%         87%    89%      Electric                          (2%)           --%
      7%        7%         13%    11%      Gas                                7%            13%
    ----      ----        ----   ----
    100%      100%        100%   100%      Total Operating Revenues          (2%)            2%
    ----      ----        ----   ----

     42%       30%         39%    31%      Fuel and Energy Interchange       39%            30%
     28%       21%         26%    22%      Operating and Maintenance         32%            16%
      5%       13%          5%    13%      Depreciation and Amortization    (64%)          (64%)
      4%        6%          5%     6%      Taxes Other Than Income          (37%)          (22%)
    ----      ----        ----   ----
     79%       70%         75%    72%      Total Operating Expenses          11%             4%
    ----      ----        ----   ----

     21%       30%         25%    28%      Operating Income                 (31%)           (5%)
    ----      ----        ----   ----

    (10%)      (8%)        (8%)   (8%)     Interest Charges                  28%             8%
    ( 1%)      (2%)        (2%)   (2%)     Other Income and Deductions      (83%)           17%
    ----      ----        ----   ----

                                           Income Before Income Taxes and
     10%       20%         15%    18%        Extraordinary Item             (48%)          (12%)
      3%        8%          6%     7%      Income Taxes                     (57%)          (15%)
    ----      ----        ----   ----
      7%       12%          9%    11%      Income Before Extraordinary Item
     (2%)       --         (1%)    --      Extraordinary Item               100%            --%
    ----      ----        ----   ----
      5%       12%          8%    11%   Net Income                          (60%)          (21%)
    ====      ====        ====   ====
</TABLE>




                                       13
<PAGE>

Second Quarter 1999 Compared To Second Quarter 1998
Operating Revenues
         Electric revenues  decreased $26 million,  or 2%, for the quarter ended
June 30, 1999  compared to the same 1998  period.  The  decrease  was  primarily
attributable  to lower  revenues  from the  distribution  business  unit of $176
million partially offset by higher revenues from the generation business unit of
$150 million. The decrease from the distribution  business unit was attributable
to $136  million  as a result of lower  volume  associated  with the  effects of
competition,  $65  million  related to the 8%  across-the-board  rate  reduction
mandated by the Final  Restructuring  Order and $12 million related to decreased
sales  volume  from  milder  weather  conditions  as  compared to the prior year
comparable  period.  These decreases were partially offset by $37 million of PJM
Interconnection,  LLC (PJM) network transmission service revenue which commenced
April 1, 1998.  PJM network  transmission  service  revenues  and  charges  were
recorded in the generation business unit in 1998 but are being recognized by the
distribution  business unit in 1999 as a result of the Federal Energy Regulatory
Commission  approval  of  the  PJM  Regional   Transmission  Owners'  rate  case
settlements. Stranded cost recovery is included in the Company's retail electric
rates beginning January 1, 1999. The increase from the generation  business unit
was attributable to $117 million from increased volume in Pennsylvania resulting
from the sale of  competitive  electric  generation  services by Exelon  Energy,
increased  wholesale  revenues  of $58  million  from the  marketing  of  excess
generation  capacity as a result of retail  competition and $14 million from the
sale of generation  from Clinton to IP,  partially  offset by $39 million of PJM
network transmission service revenue in the comparable period.

         Gas revenues  increased $6 million,  or 7%, for the quarter  ended June
30,  1999  compared  to  the  same  1998  period.  The  increase  was  primarily
attributable  to $4 million from increased  volume as a result of cooler weather
conditions in the beginning of the quarter and $2 million from increased  volume
from new and existing customers.

Fuel and Energy Interchange Expense
         Fuel and energy interchange expense increased $140 million, or 39%, for
the  quarter  ended  June 30,  1999  compared  to the  same  1998  period.  As a
percentage of revenue, fuel and interchange expenses were 42% as compared to 30%
in the comparable prior year period. These increases were attributable to higher
fuel and energy  interchange  expenses  associated with the generation  business
unit of $83 million  and the  distribution  business  unit of $57  million.  The
increase from the generation  business unit was primarily  attributable  to $129
million related to increased  volume from Exelon Energy sales,  partially offset
by lower PJM network  transmission service charges of $39 million and $3 million
of fuel  savings  associated  with the  full  return  to  service  of the  Salem
Generating  Station  (Salem) in April 1998 which  decreased the need to purchase
power to replace the output from these units. The increase from the distribution
business  unit was  attributable  to $24  million  of PJM  network  transmission
service charges,  $46 million of purchases in the spot market and $10 million of
additional  gas  purchases as a result of higher volume  associated  with cooler
weather  early  in  the  quarter  and  additional  volume  to new  and  existing
customers.  These  increases were partially  offset by $23 million of lower fuel
costs primarily as a result of lower volume associated with Customer Choice.



                                       14
<PAGE>

Operating and Maintenance Expense
         Operating and maintenance (O&M) expense  increased $83 million,  or 32%
for the quarter  ended June 30,  1999  compared  to the same 1998  period.  As a
percentage of revenue,  operating and maintenance  expenses were 28% as compared
to 21% in the comparable prior year period.  The generation  business unit's O&M
expenses increased $58 million as a result of $25 million related to the revised
Clinton  management  agreement,  $15 million associated with the Salem inventory
write-off  and true-up of 1998  reimbursement  of  joint-owner  expenses and $15
million related to the growth of unregulated  retail sales of  electricity.  The
distribution unit's O&M expenses increased approximately $22 million as a result
of additional  marketing expenses and expenses  associated with Customer Choice.
In addition,  the Company incurred additional costs of approximately $11 million
related to nuclear property  insurance and $4 million  associated with Year 2000
remediation expenditures,  partially offset by $10 million of pension credits as
a result of the performance of the investments in the Company's pension plan.

Depreciation and Amortization Expense
         Depreciation and amortization  expense decreased $103 million,  or 64%,
for the quarter  ended June 30,  1999  compared  to the same 1998  period.  As a
percentage of revenue,  depreciation and amortization expense was 5% as compared
to 13% in the comparable prior year period. The decrease was associated with the
December  1997  restructuring  charge  through  which the  Company  wrote down a
significant portion of its generating plant and regulatory assets. In connection
with this restructuring charge, the Company reduced generation-related assets by
$8.4  billion,   established  a  regulatory  asset,  Deferred  Generation  Costs
Recoverable in Current Rates of $424 million, which was fully amortized in 1998,
and established an additional  regulatory asset,  Competitive  Transition Charge
(CTC) of $5.26 billion  which will begin to be amortized in accordance  with the
terms of the Final Restructuring Order in 2000. For additional information,  see
"PART I, ITEM 1. - BUSINESS -  Deregulation  and Rate Matters," in the Company's
1998 Annual Report on Form 10-K.

Taxes Other Than Income
         Taxes other than income decreased $27 million,  or 37%, for the quarter
ended  June 30,  1999  compared  to the same 1998  period.  As a  percentage  of
revenue,  taxes other than income were 4%, as compared to 6%, in the  comparable
prior year  period.  The decrease was  primarily  attributable  to a $26 million
credit related to an adjustment to the Company's  Pennsylvania capital stock tax
base as a result of the 1997  restructuring  charge and lower gross receipts tax
of $3 million associated with lower retail electric and gas sales.

Interest Charges
         Interest charges consist of interest expense,  distributions on Company
Obligated Mandatorily  Redeemable Preferred Securities of a Partnership (COMPRS)
and  Allowance  for Funds Used During  Construction  (AFUDC).  Interest  charges
increased  $26 million,  or 28%, for the quarter ended June 30, 1999 compared to
the same 1998 period.  As a percentage of revenue,  interest charges were 10% as
compared to 8% in the comparable  prior year period.  The increase was primarily
attributable  to  interest on the  Transition  Bonds of $60  million,  partially
offset by the Company's  ongoing program to reduce and/or refinance higher cost,
long-term debt, including the use of a portion of the proceeds from the issuance
of Transition Bonds, which reduced interest charges by $34 million.



                                       15
<PAGE>

Other Income and Deductions
         Other income and deductions excluding interest charges was a loss of $5
million for the quarter ended June 30, 1999 as compared to a loss of $27 million
in the same 1998 period. The decrease of $22 million was primarily  attributable
to a $10 million write-off of a non-regulated business venture in the prior year
period and a $5 million  improvement in the performance of the Company's  equity
investments in telecommunications.

Income Taxes
         The  effective  tax rate was 32% for the quarter ended June 30, 1999 as
compared to 38% in the same 1998 period.  The decrease in the effective tax rate
was a result of tax benefits  associated  with the  implementation  of state tax
planning  strategies,  partially offset by the  non-recognition for state income
tax purposes of certain  operating  losses.  In addition,  the  disproportionate
relationship  of regulated  plant tax  adjustments to income before income taxes
and extraordinary item contributed to the decrease in the effective tax rate.

Extraordinary Item
         During  the  second   quarter  of  1999,   the   Company   incurred  an
extraordinary  charge of $26.7  million,  net of tax,  consisting  of prepayment
premiums and the write-off of unamortized  deferred  financing costs  associated
with the  early  retirement  of debt  with a portion  of the  proceeds  from the
issuance of Transition Bonds.

Preferred Stock Dividends
         Preferred  stock  dividends  for the  quarter  ended June 30, 1999 were
consistent with the same 1998 period.


Six Months Ended June 30, 1999 Compared to Six Months Ended June 30, 1998
Operating Revenues
         Electric  revenues  increased $10 million for the six months ended June
30,  1999  compared  to  the  same  1998  period.  The  increase  was  primarily
attributable  to  higher  revenues  from the  generation  business  unit of $256
million  partially offset by lower revenues from the distribution  business unit
of $246 million. The increase from the generation business unit was attributable
to $204 million from increased volume in Pennsylvania resulting from the sale of
competitive  electric generation services by Exelon Energy,  increased wholesale
revenues of $77 million from the  marketing of excess  generation  capacity as a
result of retail  competition  and $14 million from the sale of generation  from
Clinton  to IP,  partially  offset by $39  million of PJM  network  transmission
service  revenue  in  the  comparable   1998  period.   The  decrease  from  the
distribution business unit was attributable to $205 million as a result of lower
volume  associated  with the  effects  of retail  competition  and $120  million
related  to  the 8%  across-the-board  rate  reduction  mandated  by  the  Final
Restructuring Order. These decreases were partially offset by $74 million of PJM
network  transmission  service revenue and $5 million related to increased sales
volume as a result of colder  weather  conditions  in the first  quarter of 1999
partially  offset by milder weather  conditions in the second quarter of 1999 as
compared to the prior year periods.



                                       16
<PAGE>

         Gas revenues  increased  $36 million,  or 13%, for the six months ended
June 30, 1999  compared to the same 1998  period.  The  increase  was  primarily
attributable to $24 million from increased  volume as a result of cooler weather
conditions  in the  beginning of the period as compared to the prior year period
and $12 million from increased volume from new and existing customers.

Fuel and Energy Interchange Expense
         Fuel and energy interchange expense increased $222 million, or 30%, for
the six months  ended  June 30,  1999  compared  to the same 1998  period.  As a
percentage of revenue, fuel and interchange expenses were 39% as compared to 31%
in the comparable prior year period. These increases were attributable to higher
fuel and energy interchange  expenses associated with the distribution  business
unit of $119  million and the  generation  business  unit of $103  million.  The
increase from the distribution  business unit was primarily  attributable to $51
million of PJM network transmission service charges, $99 million of purchases in
the spot  market and $21  million of  additional  gas  purchases  as a result of
higher volume  associated with cooler weather early in the period and additional
volume to new and existing  customers.  These increase were partially  offset by
$55  million  of lower fuel costs as a result of lower  volume  associated  with
Customer  Choice.  The increase from the generation  business unit was primarily
attributable  to $200  million  related to increased  volume from Exelon  Energy
sales,  partially offset by $45 million of lower fuel costs as a result of lower
volume,  lower PJM network  transmission service charges of $39 million, and $19
million of fuel savings  associated with the full return to service of the Salem
Generating  Station  (Salem) in April 1998 which  decreased the need to purchase
power to replace the output from these units.

Operating and Maintenance Expense
         O&M expense increased $88 million, or 16% for the six months ended June
30, 1999 compared to the same 1998 period. As a percentage of revenue, operating
and  maintenance  expenses were 26% as compared to 22% in the  comparable  prior
year period.  The generation  business unit's O&M expenses increased $50 million
as a result of $25 million related to the revised Clinton management  agreement,
$15 million  associated with the Salem  inventory  write-off and true-up of 1998
reimbursement  of joint-owner  expenses and $10 million related to the growth of
unregulated  retail  sales of  electricity,  partially  offset by $10 million of
lower O&M  expenses  as a result of the full return to service of Salem in April
1998. The distribution  unit's O&M expenses increased  approximately $22 million
as a result of  additional  marketing  expenses  and  expenses  associated  with
Customer  Choice.  In  addition,   the  Company  incurred  additional  costs  of
approximately $11 million related to nuclear property  insurance and $16 million
associated  with Year 2000  remediation  expenditures,  partially  offset by $10
million of pension  credits as a result of the performance of the investments in
the Company's pension plan.

Depreciation and Amortization Expense
         Depreciation and amortization  expense decreased $202 million,  or 64%,
for the six months ended June 30, 1999  compared to the same 1998  period.  As a
percentage of revenue,  depreciation and amortization expense was 5% as compared
to 13% in the comparable prior year period. The decrease was associated with the
December  1997  restructuring  charge  through  which the  Company  wrote down a
significant portion of its generating plant and regulatory assets.



                                       17
<PAGE>

Taxes Other Than Income
         Taxes other than income  decreased  $33  million,  or 22%,  for the six
months ended June 30, 1999 compared to the same 1998 period.  As a percentage of
revenue,  taxes other than income were 5%, as compared to 6%, in the  comparable
prior year  period.  The decrease was  primarily  attributable  to a $30 million
credit related to an adjustment to the Company's  Pennsylvania capital stock tax
base as a result of the 1997  restructuring  charge and lower gross receipts tax
of $6 million associated with lower retail electric and gas sales.

Interest Charges
         Interest charges increased $15 million, or 8%, for the six months ended
June 30, 1999  compared to the same 1998  period.  As a  percentage  of revenue,
interest  charges were  comparable  to the prior year period at 8%. The increase
was primarily  attributable to interest on the Transition  Bonds of $60 million,
partially  offset by the Company's  ongoing  program to reduce and/or  refinance
higher cost, long-term debt, including the use of a portion of the proceeds from
the issuance of Transition Bonds, which reduced interest charges by $45 million.

Other Income and Deductions
         Other income and deductions  excluding  interest  charges was a loss of
$47 million for the six months  ended June 30, 1999 as compared to a loss of $40
million  in the same 1998  period.  The  increase  of $7 million  was  primarily
attributable  to a $15 million  write-off  of the  investment  in Grays Ferry in
connection  with the  settlement  of  litigation,  and a charge  related  to the
abandonment of an information  system of $7 million,  partially  offset by a $10
million  write-off of a non-regulated  business venture in the prior year period
and a $3  million  improvement  in  the  performance  of  the  Company's  equity
investments in telecommunications ventures.

Income Taxes
         The  effective  tax rate was 37% for the six months ended June 30, 1999
as compared to 38% in the same 1998 period.  The decrease in the  effective  tax
rate was a result of tax benefits  associated with the  implementation  of state
tax  planning  strategies,  partially  offset by the  non-recognition  for state
income  tax   purposes  of  certain   operating   losses.   In   addition,   the
disproportionate  relationship  of  regulated  plant tax  adjustments  to income
before income taxes and  extraordinary  item  contributed to the decrease in the
effective tax rate.

Extraordinary Item
         During  the  second   quarter  of  1999,   the   Company   incurred  an
extraordinary  charge of $26.7  million,  net of tax,  consisting  of prepayment
premiums and the write-off of unamortized  deferred  financing costs  associated
with the  early  retirement  of debt  with a portion  of the  proceeds  from the
issuance of Transition Bonds.

Preferred Stock Dividends
     Preferred  stock  dividends  for the six months  ended  June 30,  1999 were
consistent with the same 1998 period.


                                       18
<PAGE>


DISCUSSION OF LIQUIDITY AND CAPITAL RESOURCES
         Cash flows provided by operating  activities  decreased $258 million to
$252  million for the six months ended June 30, 1999 as compared to $510 million
in the same 1998 period.  The decrease was primarily  attributable  to less cash
generated by  operations  of $192 million and changes in working  capital of $62
million,  principally  related to accounts  receivable from  unregulated  energy
sales.

         Cash flows used by investing  activities  were $279 million for the six
months  ended June 30, 1999 as compared to $265 million in the  comparable  1998
period and consisted primarily of capital expenditures for plant.

         Cash flows provided by financing  activities  were $879 million for the
six months ended June 30, 1999, as compared to cash used in financing activities
of  $173  million  in  the  comparable  prior  year  period.  The  increase  was
attributable to the issuance of $4 billion of Transition Bonds by PETT partially
offset by the  repayment of  short-term  and  long-term  debt  aggregating  $1.5
billion and the  application of $1.5 billion of Transition  Bond proceeds to the
repurchase of common stock,  including  the  settlement of the Company's  common
stock forward purchase contract.

         On March 25, 1999,  PETT issued $4 billion of its  Transition  Bonds to
securitize a portion of the Company's  authorized  stranded cost  recovery.  The
Transition  Bonds are solely  obligations  of PETT,  secured  by the  Intangible
Transition  Property  (ITP) sold by the  Company to PETT.  Upon  issuance of the
Transition  Bonds,  a  portion  of  the  competitive  transition  charges  to be
collected by the Company to recover  stranded costs was designated as Intangible
Transition Charges (ITC). The ITC is an irrevocable  non-bypassable  usage based
charge that is  calculated  to allow for the  recovery of debt service and costs
related to the issuance of the Transition  Bonds. The ITC will be allocated from
CTC and variable distribution charges (both of which are usage based charges).

         PETT used the $3.95  billion of  proceeds  of the  Transition  Bonds to
purchase the ITP from the  Company.  Although  the  Transition  Bonds are solely
obligations of PETT, they are included in the consolidated long-term debt of the
Company.  In accordance  with the terms of the  Competition  Act, the Company is
utilizing the proceeds  principally to reduce stranded costs and capitalization.
The  Company  currently  plans to reduce  its  capitalization  in the  following
proportions: fixed and floating-rate debt, 50%; preferred securities, 7%; common
equity,  43%.  Through June 30, 1999,  the Company  utilized the net proceeds to
repurchase  38.7 million shares of Common Stock for an aggregate  purchase price
of $1.507  billion;  to retire:  $811 million of First  Mortgage  Bonds,  a $400
million term loan,  $208 million of commercial  paper,  $150 million of accounts
receivable financing and a $139 million capital lease obligation;  to repurchase
$9 million of Company Obligated Mandatorily Redeemable Preferred Securities of a
Partnership  (COMRPS);  and to pay $25  million  of  debt  issuance  costs.  The
remaining  proceeds of  approximately  $750 million are included in cash at June
30, 1999. In addition,  on July 30, 1999,  the Company  redeemed $212 million of
COMRPS.  On August 2, 1999,  the  Company  retired  $37  million of  Mandatorily
Redeemable  Preferred  Stock pursuant to the sinking fund  requirements of those
securities.  The  Company  currently  anticipates  that  it  will  complete  the
repurchase of common equity  through open market  purchases from time to time in
compliance with Securities and Exchange  Commission  rules. The number of shares
purchased  and the timing and manner or  purchases  are  dependent  upon  market
conditions.

                                       19
<PAGE>

         Although the Company has sold the ITP to PETT, the ITC revenue, as well
as all interest expense and amortization  expense associated with the Transition
Bonds,  is  reflected on the  Company's  Consolidated  Statement of Income.  The
combined  schedule for  amortization  of the CTC and ITC assets is in accordance
with the amortization  schedule set forth in the Final Restructuring Order. As a
result  of the  issuance  of the  Transition  Bonds  and  the  on-going  capital
reduction by the Company, the Company expects its debt-to-total capital ratio to
be 60%, exclusive of the Transition Bonds, upon completion of the application of
the proceeds  from  securitization.  The Company  completed  the majority of the
targeted debt and preferred  security  reductions by August 2, 1999, and expects
that the  remaining  reductions  will be completed  by December  31,  1999.  The
weighted  average  cost  of debt  and  preferred  securities  to be  retired  is
approximately   6.8%.  The  additional  interest  expense  associated  with  the
Transition Bonds, which have an effective  interest rate of approximately  5.8%,
will be partially offset by the anticipated interest savings associated with the
debt and  preferred  securities  that will be  retired.  The  Company  currently
estimates  that  the  impact  of this  additional  expense,  combined  with  the
anticipated  reduction  in common  equity,  will  result in  earnings  per share
benefits of approximately  $.15 and $.50 in 1999 and 2000,  respectively.  These
estimated  earnings  per share could change and are largely  dependent  upon the
timing  and  price of  common  stock  repurchases  and  anticipated  net  income
available to common stock.

         At June 30,  1999,  the Company had  outstanding  $226 million of notes
payable, all of which were commercial paper. In addition,  at June 30, 1999, the
Company had formal and informal lines of bank credit  aggregating  $100 million.
At June 30, 1999, the Company had no short-term investments.

         On May 3, 1999, Standard & Poor's upgraded its ratings on the Company's
overall corporate credit to "A-" from "BBB+", 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-".


YEAR 2000 READINESS DISCLOSURE
         The Year 2000 Project (Y2K 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.  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,  a temporary  inability  to process  transactions,  send
bills,  operate  generating  stations,  or engage  in  similar  normal  business
activities.  Due to the severity of the potential  impact of the Year 2000 Issue
(Y2K  Issue)  on  the  electric   utility   industry,   the  Company  adopted  a
comprehensive  schedule to achieve Y2K  readiness  by the time  specified by the
Nuclear  Regulatory  Commission  (NRC).  The  Company  has  dedicated  extensive
resources to the Project and believes it is progressing on schedule.

                                       20
<PAGE>

         The  Company  determined  that it was  required  to modify,  convert or
replace significant portions of its software and a subset of its system hardware
and embedded technology so that its computer systems will properly utilize dates
beyond  December  31,  1999.  The  Company  presently  believes  that with these
modifications,  conversions and  replacements the effect of the Y2K Issue on the
Company can be mitigated.  If such  modifications,  conversions and replacements
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 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 was
scheduled  for  completion  by July  1,  1999,  except  for a  small  number  of
modifications,  conversions  or  replacements  that are impacted by PUC changes,
vendor dates and/or are being  incorporated into scheduled plant outages between
July and November 1999. The scheduled Project  completion date was met, with the
limited anticipated exceptions noted above.

         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 the first two sections  are: (1)  inventorying  Y2K items;  (2)
assigning  priorities  to identified  items;  (3) assessing the Y2K readiness of
items  determined to be material to the Company;  (4) converting  material items
that are determined not to be Y2K 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 Y2K ready and the  replacement  of software when  available
from the supplier.  The Project has identified 363 critical systems of which 234
are IT Systems and 129  Embedded  Systems.  The current  readiness  status of IT
Systems is set forth below:

Number of Systems Progress Status

233 Systems                Y2K Ready
 1  System                 In Testing

Contingency planning for IT Systems has been completed.

         The  remaining  129  systems are the  Embedded  Systems  consisting  of
hardware  and  systems  software  other than IT Systems.  The current  readiness
status of those systems is set forth below:

Number of Systems Progress Status

120 Systems                Y2K Ready
 9  Systems                In Progress

Contingency planning for Embedded Technology has been completed.

                                       21
<PAGE>

         The Supply  Chain  section  includes  the  process of  identifying  and
prioritizing  critical  suppliers and communicating  with them about their plans
and progress in addressing  the Y2K Issue.  The process of  evaluating  critical
suppliers was completed on March 31, 1999. The Company has completed contingency
plans for all critical suppliers.

         In addition to addressing  contingency  plans with key  suppliers,  the
Company is currently  developing  contingency plans to address how to respond to
internal  events which may disrupt  normal  operations.  These plans address Y2K
risk  scenarios  that cross  departments  and business  units.  Emergency  plans
already exist that cover various aspects of the Company's business.  These plans
are being  reviewed  and updated to address  the Y2K Issue.  The Company is also
participating in industry contingency planning efforts.

         The estimated total cost of the Project is $75 million, the majority of
which is attributable to testing.  This estimate includes the Company's share of
Y2K costs for jointly owned facilities. The total amount expended on the Project
through June 30, 1999 was $44 million.  The Company  expects to fund the Project
from  operating  cash  flows.  The  Company's  failure to become Y2K 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  converted in a timely  manner,  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.  The costs of the Project and the date on which
the Company plans to complete the Y2K modifications are based on estimates, that
were derived  utilizing  numerous  assumptions of future  events,  including the
continued availability of certain resources,  third-party modification plans and
other factors,  such as regulatory  requirements that impact key systems.  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
trained  personnel,  the  ability to locate and correct  all  relevant  computer
programs and microprocessors.

         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, minimizes the possibility of significant interruptions of
normal operations.

         On July 17, 1998, an order was entered by the PUC  instituting a formal
investigation  by the Office of  Administrative  Law on Year 2000  compliance by
jurisdictional  fixed utilities and  mission-critical  service providers such as
the PJM (the  Investigation).  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


                                       22
<PAGE>

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. Pursuant to
the  formal  investigation  on  Year  2000  compliance,  the  Company  presented
testimony before the PUC on November 20, 1998.

         On February 19, 1999, the PUC issued a Secretarial Letter notifying the
Company that it had hired a consultant  to perform an  assessment of the Company
and thirteen other  utilities to evaluate the accuracy of their responses to the
compliance  program questions and testimony provided before the PUC. The Company
complied  with the PUC's  directive  in the  Secretarial  Letter to file updated
written responses to compliance questions by March 8, 1999, and to meet with the
consultant  during a one-day  on-site  review session on March 8, 1999. On March
31,  1999,   the  Company  filed   contingency   plans  with  the  PUC  for  its
mission-critical  systems  scheduled  to be  ready  after  the  March  31,  1999
deadline.

         On April 8,  1999,  the PUC  issued an order  requiring  the  Office of
Administrative  Law Judge to identify (i) utilities which have complied with the
PUC's order of July 17, 1998 (the Order); (ii) utilities which have demonstrated
good cause for an extension of time within which they will fully comply with the
Order; and (iii) those utilities which have not complied with the Order and have
not shown good cause for an extension. The PUC required that this information be
posted to the PUC internet  website and  periodically  updated.  The PUC further
ordered that the  Investigation  with respect to utilities who have demonstrated
good cause for an  extension of time remain open and under the  jurisdiction  of
the  Office  of  Administrative  Law  Judge  until  compliance  is  achieved  or
enforcement  is  warranted.  PECO  Energy  has been  identified  by the PUC as a
utility which has demonstrated  good cause for an extension of time within which
it  will  fully  comply  with  the  Order.  Additional  reporting  dates  to the
Administrative Law Judge include July 1, 1999 and October 1, 1999.

         On May 11, 1998, the NRC issued a generic letter  requiring all nuclear
plant operators to provide the NRC with the following information concerning the
operators' programs,  planned or implemented,  to address Year 2000 computer and
system issues at its facilities:  (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.

         From November 3 to November 5, 1998, members of the NRC staff conducted
an audit of the Company's Year 2000 Program for the Limerick Generating Station,
Units No. 1 and No. 2. Some of the  observations  of the audit team  included in
their written  report  issued on December 18, 1998,  were that (1) the Company's
readiness  program  is  comprehensive  and based on the  guidance  contained  in


                                       23
<PAGE>

NEI/NUSMG  97.07,  (2) the program is receiving  proper  management  support and
oversight, and (3) project schedules are being aggressively pursued.

         On April 28, 1999,  the NRC issued  Information  Notice 99-12  advising
nuclear power plant licensees that NRC staff would be conducting additional Year
2000 readiness and contingency planning  site-specific reviews at all commercial
nuclear power plants. The NRC performed its site-specific review of Peach Bottom
from May 24 to May 28, 1999,  and its review of Limerick from June 7 to June 10,
1999.

         On June 30, 1999,  PECO Energy filed its completed  response to Generic
Letter 98-01. In the response,  PECO Energy confirmed that with the exception of
five  non-safety  plant  systems,  its Peach  Bottom  Atomic  Power  Station and
Limerick  Generating  Stations are Year 2000 ready.  The Company advised the NRC
that remediation for three of the remaining  systems is scheduled for completion
by September 30, 1999, and remediation for the other two systems is scheduled to
occur during planned plant outages in September 1999.

         For additional information regarding the Year 2000 Readiness Disclosure
see "Management's  Discussion and Analysis of Financial Condition and Results of
Operations" in the Company's Annual Report to Shareholders for the year 1998.


FORWARD-LOOKING STATEMENTS
         Except for the historical  information contained herein, certain of the
matters discussed in this Report are forward-looking  statements,  including the
estimated  earnings per share benefits of the application of the Transition Bond
proceeds  for  1999  and  2000,  and  accordingly,  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, 8 and 9 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

         The Company has entered  into  interest  rate swaps to manage  interest
rate  exposure  associated  with the  issuance  of two  floating  rate series of
Transition  Bonds. At June 30, 1999, the fair value of these instruments was $52
million based on the present value difference between the contracted rate (i.e.,
hedged rate) and the market rates at that date.  A  hypothetical  50 basis point
increase or  decrease in the spot yield at June 30, 1999 would have  resulted in
an aggregate  fair value of these  interest rate swaps of $91.2 million or $10.7
million, respectively. If the derivative instruments had been terminated at June
30, 1999,  these  estimated  fair values  represent the amount to be paid by the
counterparties to the Company.

                                       24
<PAGE>

         The Company's growing market share in the retail and wholesale electric
marketplace  increases the Company's reliance on the efficient  operation of its
generating  units.  The  Company's  ability  to  fully  capitalize  on  volatile
wholesale  market prices is also  dependent on the  performance of the Company's
generating units.





                                       25
<PAGE>
PART II - OTHER INFORMATION


ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

         Information  regarding the  submission of matters to a vote of security
holders is presented in the March 31, 1999 Form 10-Q.

ITEM 5.  OTHER INFORMATION

         As  previously  reported  in the  1998  Form  10-K,  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. By letter dated May
3, 1999,  the NRC approved the  Company's  request to extend the  completion  of
Thermo-lag corrective actions at Limerick until September 30, 1999.

         As previously  reported in the 1998 Form 10-K, in October 1990, General
Electric  Company (GE) reported that crack  indications were discovered near the
seam welds of the core  shroud  assembly  in a GE Boiling  Water  Reactor  (BWR)
located outside the United States.  As a result,  GE issued a letter  requesting
that the owners of GE BWRs take interim corrective  actions,  including a review
of fabrication  records and visual  examinations of accessible areas of the core
shroud seam welds.  Each of the  reactors at Limerick  and Peach  Bottom is a GE
BWR. In accordance with industry experience and guidance, initial examination of
Limerick  Unit No. 2 was  completed  during  the April  1999  refueling  outage.
Although crack  indications were identified,  the results of the inspections and
evaluations  conclude that the condition of the Limerick Unit No. 2 core shroud,
projected  through at least the next operating cycle,  will support the required
safety  margins,   specified  in  the  ASME  code  and  reinforced  by  industry
recommendations.

        As  previously  reported  in the 1998 Form 10-K,  as a result of several
BWRs  experiencing  clogging  of some  emergency  core  cooling  system  suction
strainers,  which are part of the water supply system for  emergency  cooling of
the reactor  core,  the NRC issued a Bulletin in May 1996 to  operators  of BWRs
requesting  that measures be taken to minimize the  potential for clogging.  The
NRC proposed  three  resolution  options,  including the  installation  of large
capacity passive strainers,  with a request that actions be completed by the end
of the  unit's  first  refueling  outage  after  January  1997.  Strainers  were
installed at Peach Bottom Unit No. 3 during the October 1997  refueling  outage.
Strainers  were  installed at Peach  Bottom Unit No. 2 and  Limerick  Unit No. 1
during their  refueling  outages in October  1998 and April 1998,  respectively.
Strainers  were installed at Limerick Unit No. 2 during the April 1999 refueling
outage. The Company cannot predict what other actions,  if any, the NRC may take
in this matter.

          On June 22, 1999,  Pennsylvania Governor Tom Ridge signed into law the
Natural Gas Choice and  Competition  Act  ("Act")  which  expands  choice of gas
suppliers to residential and small commercial  customers and eliminates the five
percent gross receipts tax on gas  distribution  companies'  sales of gas. Large
commercial  and industrial  customers  have been able to choose their  suppliers
since 1984.  Currently,  approximately  one-third of the Company's  total yearly
throughput is supplied by third parties.



                                       26
<PAGE>

         The  Act  permits  gas  distribution  companies  to  continue  to  make
regulated  sales of gas to their  customers.  The Act  does not  deregulate  the
transportation  service  provided by gas  distribution  companies  which remains
subject to rate regulation.  Gas distribution companies will continue to provide
billing, metering, installation, maintenance and emergency response services.

         In  compliance  with  the  schedule   ordered  by  the  Public  Utility
Commission  ("PUC"),  the  Company  must file with the PUC by December 2, 1999 a
restructuring  plan for the  implementation  of gas  deregulation  and  customer
choice of gas service suppliers in its service territory  (Restructuring  Plan).
The  Company  expects gas to flow on its system  pursuant to customer  choice on
July 1, 2000.  The Company is currently  analyzing  the impact of the Act on its
operations. The Company believes the impact on the Company would not be material
because of the PUC's existing requirement that gas distribution companies cannot
collect  more  than  the  actual  cost of gas  from  customers,  and  the  Act's
requirement that suppliers must accept assignment or release, at contract rates,
the portion of the gas distribution company's firm interstate pipeline contracts
required to serve the suppliers' customers.


ITEM 6.  EXHIBITS AND REPORTS ON FORM 8-K
(a)      Exhibits:

         27 - Financial Data Schedule.

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

         Report,  dated  April 15,  1999  reporting  information  under "ITEM 5.
                  OTHER EVENTS" regarding AmerGen Energy Company, LLC, the joint
                  venture between the Company and British Energy,  Inc., signing
                  an interim  agreement  to purchase the Clinton  Nuclear  Power
                  Station from  Illinois  Power (IP),  a subsidiary  of Illinova
                  Corporation.

         Report,  dated June 24, 1999 reporting information under "ITEM 5. OTHER
                  EVENTS" regarding AmerGen's signing a definitive  agreement to
                  purchase  the  Nine  Mile  Point  Unit  1  Nuclear  Generating
                  Facility  from Niagara  Mohawk  Power  Corporation  (NIMO),  a
                  subsidiary of Niagara Mohawk  Holdings,  Inc. AmerGen has also
                  entered  into an agreement  to purchase  NIMO's 41%  ownership
                  interest in Nine Mile Point Unit 2 Nuclear Generating Facility
                  (NMP-2) and New York State  Electric  and Gas Corp.'s  (NYSEG)
                  18% interest in NMP-2.  NYSEG is a wholly owned  subsidiary of
                  Energy East, Inc.

         Reports on Form 8-K filed subsequent to the reporting period:

         Report,  dated July 1, 1999 reporting  information under "ITEM 5. OTHER
                  EVENTS"   regarding   AmerGen's  signing  a  definitive  asset
                  purchase agreement to purchase Clinton.



                                       27
<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
                               Vice President and
                               Senior Vice President and
                               Chief Financial Officer
                               (Chief Accounting Officer)

Date:  August 13, 1999

                                       28