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

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

                For the quarterly period ended September 30, 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  185,786,206  shares of common  stock  outstanding  on
         November 5, 1999.


                                       1
<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             Nine Months Ended
                                                               September 30,                 September 30,
                                                            1999          1998            1999           1998
<S>                                                    <C>            <C>            <C>            <C>
OPERATING REVENUES
     Electric                                          $   1,681.9    $   1,736.3    $   3,826.2    $   3,871.1
     Gas                                                      49.9           49.2          356.4          319.8
                                                       -----------    -----------    -----------    -----------

TOTAL OPERATING REVENUES                                   1,731.8        1,785.5        4,182.6        4,190.9
                                                       -----------    -----------    -----------    -----------
OPERATING EXPENSES
     Fuel and Energy Interchange                             774.2          732.9        1,739.6        1,476.1
     Operating and Maintenance                               329.3          298.3          963.7          837.5
     Depreciation and Amortization                            57.1          153.2          171.0          468.8
     Taxes Other Than Income                                  75.3           52.3          195.8          206.2
                                                       -----------    -----------    -----------    -----------
                                                           1,235.9        1,236.7        3,070.1        2,988.6
                                                       -----------    -----------    -----------    -----------
OPERATING INCOME                                             495.9          548.8        1,112.5        1,202.3
                                                       -----------    -----------    -----------    -----------

OTHER INCOME AND DEDUCTIONS
     Interest Expense                                       (108.3)         (81.9)        (296.1)        (252.9)
     Company Obligated Mandatorily Redeemable
        Preferred Securities of a  Partnership                (3.9)          (7.4)         (18.7)         (23.3)
     Allowance for Funds Used During Construction             (0.3)           0.9            1.8            2.2
     Equity in Losses of Unconsolidated Affiliates            (5.5)         (14.5)         (28.4)         (40.2)
     Other, Net                                               (6.1)           2.4          (23.0)         (11.6)
                                                       -----------    -----------    -----------    -----------

TOTAL OTHER INCOME AND DEDUCTIONS                           (124.1)        (100.5)        (364.4)        (325.8)
                                                       -----------    -----------    -----------    -----------

INCOME BEFORE INCOME TAXES AND
   EXTRAORDINARY ITEM                                        371.8          448.3          748.1          876.5

INCOME TAXES                                                 138.7          174.6          277.7          337.7
                                                       -----------    -----------    -----------    -----------

INCOME BEFORE EXTRAORDINARY ITEM                             233.1          273.7          470.4          538.8

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

NET INCOME                                                   233.1          273.7          443.7          538.8

PREFERRED STOCK DIVIDENDS                                      2.9            3.2            9.5            9.8
                                                       -----------    -----------    -----------    -----------

EARNINGS APPLICABLE TO COMMON STOCK                    $     230.2    $     270.5    $     434.2    $     529.0
                                                       ===========    ===========    ===========    ===========

AVERAGE SHARES OF COMMON STOCK
   OUTSTANDING (Millions)                                    186.6          223.1          200.5          222.8
                                                       ===========    ===========    ===========    ===========

EARNINGS PER AVERAGE COMMON SHARE:
  BASIC:
     Income Before Extraordinary Item                  $      1.23    $      1.21    $      2.30    $      2.37
     Extraordinary Item                                         --             --          (0.13)            --
                                                       -----------    -----------    -----------    -----------
     Net Income                                        $      1.23    $      1.21    $      2.17    $      2.37
                                                       ===========    ===========    ===========    ===========
  DILUTED:
     Income Before Extraordinary Item                  $      1.22    $      1.20    $      2.28    $      2.36
     Extraordinary Item                                         --             --          (0.13)            --
                                                       -----------    -----------    -----------    -----------
     Net Income                                        $      1.22    $      1.20    $      2.15    $      2.36
                                                       ===========    ===========    ===========    ===========


DIVIDENDS PER AVERAGE COMMON SHARE                     $      0.25   $       0.25    $      0.75    $      0.75
                                                       ===========   ============    ===========    ===========

</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>
<S>                                                       <C>              <C>
                                                          September 30,      December 31,
                                                              1999               1998
                                                          (Unaudited)
ASSETS

UTILITY PLANT
Electric - Transmission & Distribution                    $   3,912.1      $   3,833.8
Electric - Generation                                         1,748.5          1,713.4
Gas                                                           1,161.5          1,132.0
Common                                                          403.4            407.3
                                                          -----------      -----------
                                                              7,225.5          7,086.5
Less Accumulated Provision for Depreciation                   3,062.7          2,891.3
                                                          -----------      -----------
                                                              4,162.8          4,195.2
Nuclear Fuel, net                                               285.7            141.9
Construction Work in Progress                                   396.8            272.6
Leased Property, net                                              0.5            154.3
                                                          -----------      -----------

                                                              4,845.8          4,764.0
                                                          -----------      -----------


CURRENT ASSETS
Cash and Cash  Equivalents                                      641.8             48.1
Accounts Receivable, net
     Customer                                                   216.6             97.5
     Other                                                      415.5            213.2
Inventories, at average cost
     Fossil Fuel                                                 81.0             92.3
     Materials and Supplies                                      99.7             82.1
Other                                                            70.8             19.0
                                                          -----------      -----------

                                                              1,525.4            552.2
                                                          -----------      -----------

DEFERRED DEBITS AND OTHER ASSETS
Competitive Transition Charge                                 5,274.6          5,274.6
Recoverable Deferred Income Taxes                               623.0            614.4
Deferred Non-Pension Postretirement Benefits Costs               86.0             90.9
Investments                                                     604.5            538.1
Loss on Reacquired Debt                                          72.3             77.2
Other                                                           131.9            107.1
                                                          -----------      -----------

                                                              6,792.3          6,702.3
                                                          -----------      -----------

TOTAL                                                     $  13,163.5      $  12,018.5
                                                          ===========      ===========

</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>
<S>                                                                       <C>                 <C>
                                                                            September 30,       December 31,
                                                                                1999                1998
                                                                            (Unaudited)
CAPITALIZATION AND LIABILITIES

CAPITALIZATION
Common Shareholders' Equity:
     Common Stock (No Par)                                                $    3,617.7        $    3,589.0
     Other Paid-In Capital                                                         1.2                 1.2
     Accumulated Deficit                                                        (238.8)             (532.9)
     Treasury Stock                                                           (1,507.3)                 --

Preferred and Preference Stock:
     Without Mandatory Redemption                                                137.5               137.5
     With Mandatory Redemption                                                    55.6                92.7
Company Obligated Mandatorily Redeemable
     Preferred Securities of a Partnership                                       128.1               349.4
Long-Term Debt                                                                 6,051.3             2,919.6
                                                                          --------------      --------------
                                                                               8,245.3             6,556.5
                                                                          --------------      --------------

CURRENT LIABILITIES
Notes Payable, Bank                                                              121.8               525.0
Long-Term Debt Due Within One Year                                               146.2               361.5
Capital Lease Obligations Due Within One Year                                     --                  69.0
Accounts Payable                                                                 373.4               316.2
Taxes Accrued                                                                    254.3               170.5
Interest Accrued                                                                  70.2                61.5
Deferred Income Taxes                                                              2.8                14.1
Deferred Energy Costs - Gas                                                       13.5               (29.9)
Other                                                                            196.0               217.4
                                                                          --------------      --------------
                                                                               1,178.2             1,705.3
                                                                          --------------      --------------

DEFERRED CREDITS AND OTHER LIABILITIES
Capital Lease Obligations                                                          0.5                85.3
Deferred Income Taxes                                                          2,382.6             2,376.9
Unamortized Investment Tax Credits                                               289.3               300.0
Pension Obligation                                                               220.1               219.3
Non-Pension Postretirement Benefits Obligation                                   442.8               421.1
Other                                                                            404.7               354.1
                                                                          --------------      --------------
                                                                               3,740.0             3,756.7
                                                                          --------------      --------------

COMMITMENTS AND CONTINGENCIES (NOTE 9)

TOTAL                                                                     $   13,163.5        $   12,018.5
                                                                          ==============      ==============
</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>
<S>                                                              <C>              <C>
                                                                 Nine Months Ended September 30,

                                                                    1999              1998

CASH FLOWS FROM OPERATING ACTIVITIES

NET INCOME                                                       $    443.7       $    538.8
EXTRAORDINARY ITEM, NET OF INCOME TAXES                                26.7               --
                                                                 ----------       ----------

INCOME BEFORE EXTRAORDINARY ITEM                                      470.4            538.8

Adjustments to Reconcile Net Income to Net Cash
     Provided by Operating Activities:
Depreciation and Amortization                                         245.6            514.2
Deferred Income Taxes                                                 (14.5)           (55.8)
Amortization of Investment Tax Credits                                (10.7)           (13.6)
Deferred Energy Costs                                                  43.3             17.7
Amortization of Debt Discount/Premium                                   2.8             --
Changes in Working Capital:
     Accounts Receivable                                             (313.8)          (154.1)
     Inventories                                                       (6.3)             4.2
     Accounts Payable                                                  57.1            (18.8)
     Other Current Assets and Liabilities                              41.6            120.1
Other Items Affecting Operations                                      103.6             96.4
                                                                 ----------       ----------
CASH FLOWS PROVIDED BY OPERATING ACTIVITIES                           619.1          1,049.1
                                                                 ----------       ----------


CASH FLOWS FROM INVESTING ACTIVITIES

Investment in Plant                                                  (361.5)          (316.9)
Increase in Investments                                               (80.1)           (40.0)
                                                                 ----------       ----------

NET CASH FLOWS USED IN INVESTING ACTIVITIES                          (441.6)          (356.9)
                                                                 ----------       ----------


CASH FLOWS FROM FINANCING ACTIVITIES

Issuance of Long-Term Debt                                          3,996.8              9.8
Common Stock Repurchase                                            (1,507.3)            --
Debt Repayments                                                    (1,236.4)          (265.8)
Change in Short-Term Debt                                            (403.2)          (285.5)
Dividends on Preferred and Common Stock                              (159.5)          (176.9)
Issuance of COMRPS                                                     --               78.1
Retirement of COMRPS                                                 (221.3)           (80.9)
Retirement of Mandatorily Redeemable Preferred Stock                  (37.1)            --
Issuance of Common Stock                                               13.9             46.4
Other Items Affecting Financing                                       (29.7)            (6.9)
                                                                 ----------       ----------

NET CASH FLOWS PROVIDED BY (USED IN) FINANCING ACTIVITIES             416.2           (681.7)
                                                                 ----------       ----------

INCREASE IN CASH AND CASH EQUIVALENTS                                 593.7             10.5
                                                                 ----------       ----------

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

CASH AND CASH EQUIVALENTS AT END OF PERIOD                       $    641.8       $     43.9
                                                                 ==========       ==========
</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
September  30, 1999 and for the three and nine months then ended are  unaudited,
but  include  all  adjustments  that PECO  Energy  Company  (Company)  considers
necessary for a fair presentation of such financial statements.  All adjustments
are of a normal,  recurring nature. The year-end condensed  consolidated balance
sheet data were derived from audited financial statements but do not include all
disclosures  required  by  generally  accepted  accounting  principles.  Certain
prior-year amounts have been reclassified for comparative purposes.  These notes
should  be  read  in  conjunction  with  the  Notes  to  Consolidated  Financial
Statements  in the  Company's  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. MERGER WITH UNICOM CORPORATION
         On  September  22,  1999,  the  Company  along  with its  wholly  owned
subsidiary (Newco) and Unicom Corporation (Unicom) entered into an Agreement and
Plan of Exchange and Merger (Merger Agreement) providing for a merger of equals.
The Merger Agreement has been unanimously  approved by both companies' Boards of
Directors.  The transaction will be accounted for as a purchase with the Company
as acquiror.

         The Merger  Agreement was filed by the Company with the  Securities and
Exchange  Commission  (SEC) as an  exhibit to the Form 8-K filed  September  29,
1999. The following  description of the Merger  Agreement does not purport to be
complete and is qualified in its entirety by reference to the  provisions of the
Merger Agreement.

         The Merger  Agreement  provides for (a) the  mandatory  exchange of the
outstanding common stock, no par value, of the Company for common stock of Newco
(Newco Common  Stock) or cash (the Share  Exchange) and (b) the merger of Unicom
with and into Newco (the Merger and together with the Share Exchange, the Merger
Transaction).  In the Merger,  holders of the  outstanding  common stock, no par
value,  of Unicom  (Unicom  Common Stock) will  exchange  their shares for Newco
Common  Stock  or  cash.  The  cash   consideration   option  available  to  the
shareholders  of the  Company  and Unicom is limited  to $750  million  for each
companies'  common stock.  As a result of the Share  Exchange,  the Company will
become a wholly owned  subsidiary  of Newco.  As a result of the Merger,  Unicom
will cease to exist and its subsidiaries, including Commonwealth Edison Company,
an Illinois  corporation  (ComEd),  will  become  subsidiaries  of Newco.  Thus,
following  the  Merger  Transaction,  Newco will be a holding  company  with two
principal utility subsidiaries, ComEd and the Company.

         The Merger  Transaction is  conditioned,  among other things,  upon the
approvals of the common  shareholders  of both  companies and the  completion of
regulatory  procedures with the appropriate  regulatory agencies.  The companies
intend to  register  Newco as a holding  company  with the SEC under the  Public
Utility Holding Company Act of 1935.

                                       6
<PAGE>
3. 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>                        <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               6.02% (a)       March 1, 2004              March 1, 2006
         A-4           $458.5               5.80%           March 1, 2005              March 1, 2007
         A-5           $464.6               6.10% (a)       September 1, 2007          March 1, 2009
         A-6           $993.4               6.05%           March 1, 2007              March 1, 2009
         A-7           $896.6               6.13%           September 1, 2008          March 1, 2009
</TABLE>


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

         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 September 30, 1999, the fair value of these instruments was
$75 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  September  30, 1999 would have
resulted in an aggregate fair value of these interest rate swaps of $111 million
or $36 million,  respectively. If the derivative instruments had been terminated
at September 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

                                       7
<PAGE>

Generation  Customer Choice and Competition  Act, the Company is utilizing these
proceeds  principally to reduce its stranded  costs and related  capitalization.
Through  September 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,   a  $139  million  capital  lease  obligation  and  $37  million  of
Mandatorily  Redeemable  Preferred  Stock;  to redeem  $221  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  $450  million  are  included  in cash  and  cash  equivalents  at
September 30, 1999.

         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.


4. 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.

          In 1999, the Company completed the redesign of its internal  reporting
structure to separate its distribution, generation, 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 consists of its
electric  transmission  and  distribution  services,  regulated  retail sales of
generation services and retail gas sales and services.  The Company's generation
business  unit  consists of the operation of its  generation  assets,  its power
marketing  group and its  unregulated  retail  energy  supplier.  The  Company's
ventures business unit consists of its infrastructure  services business and its
telecommunications equity investments.

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

                                       8
<PAGE>
Quarter Ended September 30, 1999 as compared to the Quarter Ended
September 30, 1998
<TABLE>
<CAPTION>
<S>                   <C>                <C>               <C>              <C>                <C>               <C>
                                                                                            Intersegment
                    Distribution        Generation         Ventures       Corporate           Revenues         Consolidated
                    ------------        ----------         --------       ---------           --------         ------------
Revenues:
    1999               $  882.1           $1,084.9          $  13.7          $     --           $(248.9)          $1,731.8
    1998               $1,075.5            $ 993.0          $    --          $     --           $(283.1)          $1,785.5
EBIT (a):
    1999                 $382.3            $ 151.6           $( 9.4)         $ ( 40.2)                            $  484.3
    1998                 $500.9            $ 121.3          $( 34.6)         $ ( 50.9)                            $  536.7



Nine Months Ended September 30, 1999 as compared to Nine Months Ended
September 30, 1998

Revenues:
    1999               $2,528.6           $2,267.6          $  15.0          $     --           $(628.6)          $4,182.6
    1998               $2,931.2           $2,022.6          $    --          $     --           $(762.9)          $4,190.9
EBIT (a):
    1999               $1,032.9            $ 197.1          $( 46.2)         $( 122.7)                            $1,061.1
    1998               $1,171.2            $ 212.4          $( 93.3)         $( 139.8)                            $1,150.5
Total Assets:
    1999              $10,642.1(b)        $1,857.9           $238.9            $424.6                            $13,163.5
    1998              $10,001.9           $1,728.7           $222.3            $395.1                            $12,348.0

<FN>
 (a) EBIT - Earnings Before Interest and Income Taxes.
 (b) Includes $450 million of proceeds from securitization of stranded costs.
</FN>
</TABLE>


5.   EARNINGS PER SHARE
         Diluted  earnings per average  common share is  calculated  by dividing
earnings  applicable  to common stock by the average  number of shares of common
stock  outstanding  after  giving  effect to stock  options  issuable  under the
Company's  stock option plans which are  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                 Nine Months Ended
                                                                  September 30,                      September 30,
                                                                 --------------                     --------------
                                                          1999                 1998             1999               1998
                                                         -----                 -----            -----             -----
<S>                                                      <C>                   <C>              <C>               <C>
Average Common Shares Outstanding                        186.6                 223.1            200.5             222.8

Assumed Exercise of Stock Options                          1.5                   1.9              1.5               1.7
                                                         -----                 -----            -----             -----

Potential Average Dilutive
  Common Shares Outstanding                              188.1                 225.0            202.0             224.5
                                                         =====                 =====            =====             =====
</TABLE>

                                       9
<PAGE>
6. 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  September  30,  1999,  the Company had sold a $275  million
interest  in  accounts  receivable,  consisting  of a $226  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 $49
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 September
30, 1999,  met such  requirements.  At September  30, 1999,  the average  annual
service rate charged to the Company, computed on a daily basis on the portion of
the accounts receivable sold but not yet collected, was 5.22%.


7. AMERGEN ENERGY COMPANY
         AmerGen Energy  Company,  LLC (AmerGen),  the joint venture between the
Company and British Energy, plc (British Energy), has entered into agreements to
purchase  Three Mile Island Unit No. 1 Nuclear  Generating  Facility,  Nine Mile
Point Unit 1 Nuclear Generating  Facility, a 59% undivided interest in Nine Mile
Point  Unit  2  Nuclear  Generating  Facility,  Clinton  Nuclear  Power  Station
(Clinton) and Oyster Creek Nuclear Generating Facility.


8. CLINTON NUCLEAR POWER STATION
         Under the Amended Management Agreement, effective April 1, 1999 between
the Company and  Illinois  Power (IP)  providing  for the  provision  of certain
management services by the Company to IP in support of Clinton's outage recovery
efforts and operations, 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.  These costs are  reflected in the
Company's O&M expenses.  IP will continue to pay indirect  costs such as pension
benefits,  payroll taxes and property taxes. Following the restart of Clinton on
June 2, 1999, and through  December 31, 1999, the Company has agreed to sell 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 third quarter and for the nine months
ended September 30, 1999, the Company recognized revenue from sales to IP of $47
million and $62 million,  respectively,  and O&M expenses  related to Clinton of
$23 million and $48 million, respectively.


9. COMMITMENTS AND CONTINGENCIES
         For information  regarding the Company's capital  commitments,  nuclear
insurance,  nuclear  decommissioning and spent fuel storage, energy commitments,
environmental  issues  and


<PAGE>
litigation,  see Note 5 of Notes to  Consolidated  Financial  Statements for the
year ended December 31, 1998.

         At  September  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 $3 million in 1999,
$88 million in 2000,  $47 million in 2001,  $17 million in 2002,  $10 million in
2003 and $18 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
September  30,  1999,  the Company  had  accrued  $58 million for  environmental
investigation and remediation costs, including $32 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.

         In  November   1997,   the  Company   signed  an  agreement   with  the
Massachusetts  Health and Education Facilities Authority (HEFA) to provide power
to  HEFA's  members  and  employees  in  anticipation  of  deregulation  of  the
electricity industry in Massachusetts. In the third quarter of 1999, the Company
determined that based upon anticipated prices of energy in Massachusetts through
the  remaining  life  of the  HEFA  contract  that  it had  incurred  a loss  of
approximately $36 million.

         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
partnership interest in Grays Ferry to the remaining partners.  Accordingly,  in
the first  quarter,  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
the power purchase agreement is recorded in Fuel and Energy Interchange  Expense
on the  Company's  Statement of Income for the nine months ended  September  30,
1999.  The  settlement  also resolved the  litigation  with  Westinghouse  Power
Generation and The Chase Manhattan Bank.

         During the third quarter of 1999, the Company  revised its estimate for
losses  associated  with the Grays Ferry power  purchase  agreement and reversed
approximately $38 million of reserves.

         At December 31, 1998, the Company incurred a charge of $125 million for
its Early Retirement and Separation  Program  relating to 1,157  employees.  The
reserve for  separation  benefits was  approximately  $47 million,  of which $24
million was paid through September 30, 1999.  Retirement benefits are being paid
to the retirees over their lives. Of the 1,157 employees,

                                       11
<PAGE>

344 were eligible for and have taken the  retirement  incentive  program and 401
employees were  terminated  with the enhanced  severance  benefit  program.  The
remaining employees are scheduled for termination through the end of June 2000.


10. 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.

         As part of its wholesale marketing operations,  the Company enters 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.

         The Company  records  revenues and expenses  associated with the energy
commitments   at  the  time  the   underlying   physical   transaction   closes.
Additionally,  the Company  evaluates  its portfolio of energy  commitments  for
impairment  based on the lower of cost or market.  At September  30,  1999,  the
Company  concluded that no energy  commitments were impaired other than the HEFA
and Grays Ferry power purchase agreements as described above.


                                       12
<PAGE>

11. SUBSEQUENT EVENTS

Exelon Infrastructure Services, Inc. Acquisitions
         In  October  1999,  Exelon  Infrastructure  Services,  Inc.  (EIS),  an
unregulated  subsidiary  of the  Company,  acquired  the  stock or assets of six
utility  service  contracting  companies  for an  aggregate  purchase  price  of
approximately  $240  million,  including  stock of EIS.  The  acquisitions  were
accounted for using the purchase method of accounting.  The preliminary estimate
of the excess of purchase  price over the fair value of net assets  acquired was
approximately $160 million.

Debt Refinancing
         On October 14, 1999, the Company refinanced $156.4 million of pollution
control notes with a weighted  average  interest rate of 7.1% with new pollution
control notes in the same aggregate amount with a weighted average interest rate
of 5.2%.  The  Company  incurred  $16.5  million  of costs  associated  with the
refinancing  which  consisted of $11.2 million for prepayment  premiums and $5.3
million in unamortized debt discount,  deferred  financing fees and tender offer
costs associated with the original  pollution control notes. These costs will be
reflected as an extraordinary item in the fourth quarter of 1999.










                                       13
<PAGE>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS

GENERAL

         On  September  22,  1999,  the  Company  along  with its  wholly  owned
subsidiary (Newco) and Unicom Corporation (Unicom) entered into an Agreement and
Plan of Exchange and Merger (Merger Agreement) providing for a merger of equals.
The Merger Agreement has been unanimously  approved by both companies' Boards of
Directors.  The transaction will be accounted for as a purchase with the Company
as acquiror.

         The Merger  Agreement was filed by the Company with the  Securities and
Exchange  Commission  (SEC) as an  exhibit to the Form 8-K filed  September  29,
1999. The following  description of the Merger  Agreement does not purport to be
complete and is qualified in its entirety by reference to the  provisions of the
Merger Agreement.

         The Merger  Agreement  provides for (a) the  mandatory  exchange of the
outstanding common stock, no par value, of the Company for common stock of Newco
(Newco Common  Stock) or cash (the Share  Exchange) and (b) the merger of Unicom
with and into Newco (the Merger and together with the Share Exchange, the Merger
Transaction).  In the Merger,  holders of the  outstanding  common stock, no par
value,  of Unicom  (Unicom  Common Stock) will  exchange  their shares for Newco
Common  Stock  or  cash.  The  cash   consideration   option  available  to  the
shareholders  of the  Company  and Unicom is limited  to $750  million  for each
companies'  common stock.  As a result of the Share  Exchange,  the Company will
become a wholly owned  subsidiary  of Newco.  As a result of the Merger,  Unicom
will cease to exist and its subsidiaries, including Commonwealth Edison Company,
an Illinois  corporation  (ComEd),  will  become  subsidiaries  of Newco.  Thus,
following  the  Merger  Transaction,  Newco will be a holding  company  with two
principal utility subsidiaries, ComEd and the Company.

         The Merger  Transaction is  conditioned,  among other things,  upon the
approvals of the common  shareholders  of both  companies and the  completion of
regulatory  procedures with the appropriate  regulatory agencies.  The companies
intend to  register  Newco as a holding  company  with the SEC under the  Public
Utility Holding Company Act of 1935.

         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 September
30, 1999,  approximately  234,000  customers  representing  15% of the Company's
residential customers, 26% of its commercial customers and 59% 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  140,000 business and residential  customers
located throughout Pennsylvania.

                                       14
<PAGE>
         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 PETT 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  $0.15 and $0.50 in 1999 and 2000,
respectively.  These estimated  earnings per share benefits 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 includes its distribution,
generation,  and ventures operations.  The Company's  distribution business unit
consists of its  electric  transmission  and  distribution  services,  regulated
retail  sales of  generation  services  and retail gas sales and  services.  The
Company's  generation  business unit consists of the operation of its generation
assets,  its power marketing group and its unregulated  retail energy  supplier.
The Company's  ventures  business unit consists of its  infrastructure  services
business and its telecommunications equity investments.



RESULTS OF OPERATIONS

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

         In the third quarter of 1999, the Company  reclassified  the results of
operations  of  its  infrastructure  services  business,  Exelon  Infrastructure
Services, Inc. (EIS), in its Condensed Consolidated Statement of Operations from
Other Income and  Deductions.  EIS provides  infrastructure  services  including
infrastructure  construction,  operation  management and maintenance services to
owners of electric, gas and telecommunications systems, including industrial and
commercial customers, utilities and municipalities.

                                       15
<PAGE>
         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).
These costs are reflected in the Company's O&M expenses.  IP is responsible  for
indirect  costs such as pension  benefits,  payroll  taxes and  property  taxes.
Following the restart of Clinton on June 2, 1999, and through December 31, 1999,
the Company has agreed to sell 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>
<S>    <C>     <C>             <C>       <C>                                                 <C>                     <C>
Revenue and Expense Items as a
Percentage of Total Operating
Revenues                                                                                      Percentage Dollar Changes
                                                                                                     1999 vs. 1998
        Quarter                 Nine Months                                               Quarter               Nine Months
         Ended                     Ended                                                   Ended                   Ended
      September 30,            September 30,                                            September 30,             September 30,
      1999     1998           1999     1998
      ----     ----           ----     ----
       97%     97%             91%       92%      Electric                                   (3%)                    (1%)
        3%      3%              9%        8%      Gas                                         1%                     11%
      ----    ----            ----      ----
      100%    100%            100%      100%      Total Operating Revenues                   (3%)                    --
      ----    ----            ----      ----

       45%     41%             41%       35%      Fuel and Energy Interchange                 6%                     18%
       19%     17%             23%       20%      Operating and Maintenance                  10%                     15%
        3%      8%              4%       11%      Depreciation and Amortization             (63%)                   (64%)
        4%      3%              5%        5%      Taxes Other Than Income                    44%                     (5%)
      ----    ----            ----      ----
       71%     69%             73%       71%      Total Operating Expenses                   (1%)                     3%
      ----    ----            ----      ----

       29%     31%             27%       29%      Operating Income                          (10%)                    (7%)
      ----    ----            ----      ----

       (7s%)    (5%)            (7%)      (6%)     Interest Charges                           27%                     14%
                                                  Equity in Losses of
       --      (1%)            (1%)      (1%)       Unconsolidated Affiliates               (62%)                   (29%)
       (1%)    --              (1%)      (1%)     Other Income and Deductions              (354%)                    98%
      ----    ----            ----      ----

                                                  Income Before Income Taxes and
       21%     25%             18%       21%        Extraordinary Item                      (17%)                   (15%)
        8%     10%              6%        8%      Income Taxes                              (21%)                   (18%)
      ----    ----            ----      ----
       13%     15%             12%       13%      Income Before Extraordinary Item           15%                     13%
       --      --              (1%)      --       Extraordinary Item                         --                      --
      ----    ----            ----      ----
       13%     15%             11%       13%      Net Income                                (15%)                   (18%)
      ====    ====            ====      ====
</TABLE>

Third Quarter 1999 Compared To Third Quarter 1998
Operating Revenues
         Electric revenues  decreased $54 million,  or 3%, for the quarter ended
September  30,  1999  compared  to  the  same  1998  period.  The  decrease  was
attributable  to lower  revenues  from the  distribution  business  unit of $194
million partially offset by higher revenues from the generation

                                       16
<PAGE>

business unit of $125 million and the ventures business unit of $15 million. The
decrease from the distribution business unit was primarily  attributable to $171
million as a result of lower volume  associated with the effects of competition,
$71 million related to the 8%  across-the-board  rate reduction  mandated by the
Final  Restructuring  Order and $42  million  related to  decreased  volume from
existing  customers.  These  decreases were  partially  offset by $51 million of
increased  volume due to warmer weather  conditions as compared to the same 1998
period and $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 primarily  attributable  to $136 million
from  increased  volume in  Pennsylvania  resulting from the sale of competitive
electric  generation  services by Exelon Energy and $47 million from the sale of
generation from Clinton to IP, partially offset by decreased  wholesale revenues
of $21  million  as a result of lower  volume  and $39  million  of PJM  network
transmission  service revenue in the same 1998 period.  The increase in revenues
from the  ventures  business  unit is  attributable  to  infrastructure  service
revenues.

         Gas  revenues  increased  $1  million,  or 1%,  for the  quarter  ended
September 30, 1999 compared to the same 1998 period.  The increase was primarily
attributable to increased volume from new and existing customers.

Fuel and Energy Interchange Expense
         Fuel and energy interchange  expense increased $41 million,  or 6%, for
the quarter  ended  September  30, 1999  compared to the same 1998 period.  As a
percentage of revenue, fuel and interchange expenses were 45% as compared to 41%
in the comparable  prior year period.  The increase was  attributable  to higher
fuel and energy interchange  expenses associated with the distribution  business
unit of $40 million and the generation business unit of $1 million. The increase
from the  distribution  business  unit was  attributable  to $24  million of PJM
network  transmission  service  charges and $16 million of purchases in the spot
market.   The  increase  from  the   generation   business  unit  was  primarily
attributable  to $259  million  related to increased  volume from Exelon  Energy
sales,  offset by $219 million of fuel savings from  wholesale  operations  as a
result of lower  volume and  efficient  operation  of the  Company's  generating
assets and lower PJM network transmission service charges of $39 million.

Operating and Maintenance Expense
         O&M  expense  increased  $31  million,  or 10%  for the  quarter  ended
September 30, 1999 compared to the same 1998 period. As a percentage of revenue,
operating and maintenance expenses were 19% as compared to 17% in the comparable
prior year period.  The generation  business  unit's O&M expenses  increased $34
million  primarily  as a result of $23 million  related to the  revised  Clinton
management agreement,  $8 million for the abandonment of a billing system and $6
million related to the growth of unregulated  retail sales of  electricity.  The
distribution  business unit's O&M expenses  increased  approximately  $1 million
primarily  as a result of  additional  expenses  of $11 million  resulting  from
restoration efforts related to Hurricane Floyd offset by

                                       17
<PAGE>

lower customer expenses,  transmission and distribution  expenses and regulatory
commissions  aggregating $10 million.  The ventures business unit's O&M expenses
increased  $15  million  related to the  infrastructure  services  business.  In
addition,  the Company  experienced lower  administrative and general expense of
$18  million  and  lower  pension  expense  of $7  million  as a  result  of the
performance of the  investments in the Company's  pension plan.  These decreases
were  partially  offset by $4  million  associated  with  Year 2000  remediation
expenditures.

Depreciation and Amortization Expense
         Depreciation and amortization  expense  decreased $96 million,  or 63%,
for the quarter ended September 30, 1999 compared to the same 1998 period.  As a
percentage of revenue,  depreciation and amortization expense was 3% as compared
to 8% 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 increased $23 million,  or 44%, for the quarter
ended  September 30, 1999  compared to the same 1998 period.  As a percentage of
revenue,  taxes other than income were 4%, as compared to 3%, in the  comparable
prior year period.  The increase was primarily  attributable  to a refund of the
Company's Pennsylvania gross receipts tax in September 1998.

Interest Charges
         Interest charges consist of interest expense,  distributions on Company
Obligated Mandatorily  Redeemable Preferred Securities of a Partnership (COMRPS)
and  Allowance  for Funds Used During  Construction  (AFUDC).  Interest  charges
increased $24 million, or 27%, for the quarter ended September 30, 1999 compared
to the same 1998 period. As a percentage of revenue, interest charges were 7% as
compared to 5% in the comparable  prior year period.  The increase was primarily
attributable  to  interest on the  Transition  Bonds of $66  million,  partially
offset by the Company's  reduction and/or refinancing of 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 $42 million.

Equity in Losses of Unconsolidated Affiliates
         Equity in losses of  unconsolidated  affiliates  was $6 million for the
quarter  ended  September  30,  1999 as compared to $15 million in the same 1998
period.  The lower losses  represent a 62%  improvement in the Company's  equity
investments in telecommunications as a result of customer base growth.

                                       18
<PAGE>
Other Income and Deductions
         Other income and deductions  excluding  interest  charges and equity in
losses of  unconsolidated  affiliates  was a loss of  $6 million for the quarter
ended  September  30,  1999 as compared to income of $2 million in the same 1998
period. The decrease of $8 million was primarily attributable to a settlement of
a purchase power agreement in the third quarter of 1998.

Income Taxes
         The effective  tax rate was 37.3% for the quarter  ended  September 30,
1999 as compared to 38.9% in the same 1998 period. The decrease in the effective
tax rate was primarily  attributable  to an income tax benefit of  approximately
$11 million related to the favorable resolution of certain outstanding issues in
connection  with the  settlement  of an Internal  Revenue  Service audit and 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.

Preferred Stock Dividends
         Preferred  stock  dividends  for the quarter  ended  September 30, 1999
decreased  $0.3 million or 9% as compared to the same 1998 period.  The decrease
was  attributable  to the  retirement of $37 million of  Mandatorily  Redeemable
Preferred  Stock in August 1999 with a portion of the proceeds from the issuance
of Transition Bonds.


Nine Months Ended September 30, 1999 Compared to Nine Months Ended
September 30, 1998
Operating Revenues
         Electric  revenues  decreased  $45 million,  or 1%, for the nine months
ended  September  30, 1999  compared to the same 1998  period.  The decrease was
primarily  attributable to lower revenues from the distribution business unit of
$441 million  partially  offset by higher revenues from the generation  business
unit of $380  million and $15  million  from the  ventures  business  unit.  The
decrease from the distribution business unit was primarily  attributable to $393
million  as a result  of lower  volume  associated  with the  effects  of retail
competition and $249 million related to the 8%  across-the-board  rate reduction
mandated by the Final Restructuring Order. These decreases were partially offset
by $111  million of PJM  network  transmission  service  revenue and $83 million
related to  increased  volume as a result of colder  weather  conditions  in the
first quarter of 1999,  warmer weather  conditions in the third quarter of 1999,
and additional  volume related to new and existing  customers as compared to the
same 1998 periods.  The increase from the generation business unit was primarily
attributable  to $341 million from increased  volume in  Pennsylvania  resulting
from the sale of  competitive  electric  generation  services by Exelon  Energy,
increased  wholesale  revenues  of $56  million  from the  marketing  of  excess
generation  capacity  as a result  of retail  competition  and  revenues  of $62
million from the sale of generation from Clinton to IP,  partially offset by $78
million of PJM network transmission service revenue in the same 1998 period. The
increase in revenues from the ventures  business unit is primarily  attributable
to infrastructure service revenues.

         Gas revenues  increased $37 million,  or 11%, for the nine months ended
September 30, 1999 compared to the same 1998 period.  The increase was primarily
attributable to $24 million

                                       19
<PAGE>

from increased volume as a result of cooler weather  conditions in the beginning
of the period as compared to the same 1998 period and $13 million from increased
volume from new and existing customers.

Fuel and Energy Interchange Expense
         Fuel and energy interchange expense increased $264 million, or 18%, for
the nine months ended September 30, 1999 compared to the same 1998 period.  As a
percentage of revenue, fuel and interchange expenses were 41% as compared to 35%
in the comparable  prior year period.  The increase was  attributable  to higher
fuel and energy interchange  expenses associated with the distribution  business
unit of $160  million and the  generation  business  unit of $104  million.  The
increase from the distribution  business unit was attributable to $75 million of
PJM network  transmission  service charges, $64 million of purchases in the spot
market  and $21  million  of  additional  volume  related  to new  and  existing
customers.  The  increase  from  the  generation  business  unit  was  primarily
attributable  to $453  million  related to increased  volume from Exelon  Energy
sales,  partially  offset  by  $252  million  of  fuel  savings  from  wholesale
operations as a result of lower volume and efficient  operation of the Company's
generating  assets,  lower  PJM  network  transmission  service  charges  of $78
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  $126 million,  or 15% for the nine months ended
September 30, 1999 compared to the same 1998 period. As a percentage of revenue,
operating and maintenance expenses were 23% as compared to 20% in the comparable
prior year period.  The generation  business  unit's O&M expenses  increased $89
million  primarily  as a result of $48 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,  $15  million of
charges related to the  abandonment of two  information  systems and $17 million
related  to the  growth  of  unregulated  retail  sales  of  electricity.  These
decreases were 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  business
unit's O&M expenses  increased $15 million  primarily as a result of $11 million
of  additional  expenses  related  to  restoration  activities  as a  result  of
Hurricane Floyd. The ventures business unit's O&M expenses increased $15 million
related to the  infrastructure  services  business.  In  addition,  the  Company
incurred  additional costs of $20 million  associated with Year 2000 remediation
expenditures  and $12 million related to nuclear property  insurance,  partially
offset by $17 million of lower pension expense as a result of the performance of
the  investments  in the  Company's  pension plan and lower  administrative  and
general expenses of $10 million.

Depreciation and Amortization Expense
         Depreciation and amortization  expense decreased $298 million,  or 64%,
for the nine months ended  September  30, 1999 compared to the same 1998 period.
As a percentage  of revenue,  depreciation  and  amortization  expense was 4% as
compared to 11% 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-

                                       20
<PAGE>

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  $10  million,  or 5%, for the nine
months  ended  September  30,  1999  compared  to the  same  1998  period.  As a
percentage  of revenue,  taxes other than income were 5%,  which was  consistent
with the comparable prior year period.  The decrease was primarily  attributable
to a $34 million credit  related to an adjustment to the Company's  Pennsylvania
capital stock tax base as a result of the 1997  restructuring  charge  partially
offset by a $22 million refund of the Company's  Pennsylvania gross receipts tax
in September 1998.

Interest Charges
         Interest  charges  increased  $39 million,  or 14%, for the nine months
ended  September 30, 1999  compared to the same 1998 period.  As a percentage of
revenue, interest charges were 7% as compared to 6% in the comparable prior year
period.  The increase was primarily  attributable  to interest on the Transition
Bonds of $130  million,  partially  offset  by the  Company's  reduction  and/or
refinancing  of higher  cost,  long-term  debt from the use of a portion  of the
proceeds from the issuance of Transition  Bonds,  which reduced interest charges
by $91 million.

Equity in Losses of Unconsolidated Affiliates
         Equity in losses of  unconsolidated  affiliates was $28 million for the
nine months ended September 30, 1999 as compared to $40 million in the same 1998
period.  The lower losses  represent a 29%  improvement in the Company's  equity
investments in telecommunications as a result of customer base growth.

Other Income and Deductions
         Other income and deductions  excluding  interest  charges and equity in
earnings  of  unconsolidated  affiliates  was a loss of $23 million for the nine
months ended September 30, 1999 as compared to a loss of $12 million in the same
1998 period.  The increase of $11 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 settlement of a power  purchase  agreement in the
third  quarter  of  1998,  partially  offset  by a $10  million  write-off  of a
non-regulated business venture in the prior year period.

Income Taxes
         The  effective  tax rate was 37.1% for the nine months ended  September
30,  1999 as  compared  to 38.5% in the same 1998  period.  The  decrease in the
effective  tax rate was  primarily  attributable  to an income  tax  benefit  of
approximately  $11  million  related  to the  favorable  resolution  of  certain
outstanding  issues in connection  with the  settlement  of an Internal  Revenue
Service audit and 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.

                                       21
<PAGE>
Preferred Stock Dividends
         Preferred  stock dividends for the nine months ended September 30, 1999
decreased  $0.3 million or 3% as compared to the same 1998 period.  The decrease
was  attributable  to the  retirement of $37 million of  Mandatorily  Redeemable
Preferred  Stock in August 1999 with a portion of the proceeds from the issuance
of the Transition Bonds.



DISCUSSION OF LIQUIDITY AND CAPITAL RESOURCES

         Cash flows provided by operating  activities  decreased $430 million to
$619 million for the nine months ended  September 30, 1999 as compared to $1,049
million in the same 1998 period. The decrease was primarily attributable to less
cash  generated by operations of $264 million and changes in working  capital of
$173 million, principally related to accounts receivable from unregulated energy
sales.

         Cash flows used by investing  activities were $442 million for the nine
months  ended  September  30, 1999 as compared to $357  million in the same 1998
period. The increase was attributable to capital expenditures and investments in
infrastructure services businesses and other ventures business unit investments.

         Cash flows provided by financing  activities  were $416 million for the
nine months  ended  September  30,  1999,  as compared to cash used in financing
activities  of  $682  million  in  the  same  1998  period.   The  increase  was
attributable to the issuance of $4 billion of PETT Transition  Bonds,  partially
offset by the use of Transition Bond proceeds to: repay short-term and long-term
debt  aggregating  $1.6  billion,  repurchase  $1.5  billion  of  common  stock,
including  the  settlement  of  the  Company's  common  stock  forward  purchase
contract,   redemption  $221  million  of  COMRPS  and  retire  $37  million  of
Mandatorily Redeemable Preferred Stock.

         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 CTCs 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  by  applying  the
proceeds in the following  proportions:  debt, 50%;  preferred  securities,  7%;
common equity,  43%.  Through  September 30, 1999, the Company  utilized the net
proceeds to repurchase 38.7 million

                                       22
<PAGE>
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,  a
$139 million capital lease obligation and $37 million of Mandatorily  Redeemable
Preferred  Stock;  to redeem $221  million of COMRPS;  and to pay $25 million of
debt issuance costs. The remaining  proceeds of  approximately  $450 million are
included  in cash and cash  equivalents  at  September  30,  1999.  The  Company
currently  anticipates  that it will  complete the  repurchase  of common equity
through open market  purchases  from time to time in compliance  with SEC rules.
The  number of shares  purchased  and the timing  and  manner of  purchases  are
dependent upon market conditions.

         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. The
Company  completed  the majority of the  targeted  debt and  preferred  security
reductions  by August 2, 1999,  and  expects the  application  of proceeds to be
substantially  completed by December 31, 1999. The weighted average cost of debt
and  preferred  securities  that have been retired is  approximately  6.8%.  The
additional   interest  expense  associated  with  the  Transition  Bonds,  which
currently  have an  effective  interest  rate  of  approximately  5.8%,  will be
partially offset by the interest savings  associated with the debt and preferred
securities  that have been 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 $0.15
and $0.50 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 September  30,  1999,  the Company had  outstanding  $122 million of
notes payable, all of which were commercial paper. In addition, at September 30,
1999,  the  Company  had  available  formal and  informal  lines of bank  credit
aggregating $100 million and available  revolving credit facilities  aggregating
$900 million which support its commercial paper program.  At September 30, 1999,
the Company had no short-term investments.

         On October 14, 1999, the Company refinanced $156.4 million of pollution
control notes with a weighted  average  interest rate of 7.1% with new pollution
control notes in the same aggregate amount with a weighted average interest rate
of 5.2%.  The  Company  incurred  $16.5  million  of costs  associated  with the
refinancing  which  consisted of $11.2 million for prepayment  premiums and $5.3
million in unamortized debt discount,  deferred  financing fees and tender offer
costs associated with the original  pollution control notes. These costs will be
reflected as an extraordinary item in the fourth quarter of 1999.

         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

                                       23
<PAGE>

preferred stock to "BBB" from "BBB-".  On September 24, 1999,  Standard & Poor's
placed  the   Company's   long-term   ratings  on   CreditWatch   with  negative
implications.


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 Y2K
Project and has achieved readiness as of November 5, 1999, as planned.

         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 has been mitigated. If such modifications,  conversions and replacements
had not been made, or had not been completed in a timely  manner,  the Y2K Issue
could have had 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 has utilized both internal and external  resources to
reprogram,  or  replace  and test  software  and  computer  systems  for the Y2K
Project. These systems were scheduled for completion by July 1, 1999, except for
a small number of modifications,  conversions or replacements that were impacted
by PUC changes, vendor dates and/or were being incorporated into scheduled plant
outages between July and November 1999. All systems are now Y2K ready.

         The Y2K  Project  was 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 were: (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.

                                       24
<PAGE>
The IT Systems  section  included both the conversion of  applications  software
that was not Y2K ready and the  replacement  of software when available from the
supplier.  The Y2K Project has identified 363 critical  systems of which 234 are
IT Systems and 129 are Embedded  Systems.  As of November 5, 1999,  all of these
systems are Y2K ready.  In  addition,  contingency  planning  for IT Systems and
Embedded systems has been completed.

         The Supply  Chain  section  included  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,
contingency   plans  have  been  developed  to  address   operations   that  may
inadvertently  have a Y2K  related  disruption.  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 have
been  reviewed  and  updated  to  address  the Y2K  Issue.  The  Company is also
participating in industry contingency planning efforts.

         The current estimated total cost of the Y2K Project is $70 million, the
majority of which is  attributable  to  testing.  This  represents  a $5 million
reduction  of the  previously  estimated  total  cost of the Y2K  Project.  This
estimate includes the Company's share of Y2K costs for jointly owned facilities.
The total amount expended on the Y2K Project through  September 30, 1999 was $50
million.  The Company is funding the Y2K 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
has  developed  contingency  plans to address  how to respond to events that may
disrupt normal operations, including activities with PJM. The total costs of the
Y2K  Project  are based on  estimates,  that  were  derived  utilizing  numerous
assumptions of future events,  including the continued  availability  of certain
resources,  the  execution of  contingency  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 and the
need to execute contingency plans.

         The  Y2K  Project   significantly   reduced  the  Company's   level  of
uncertainty about the Y2K Issue. The Company believes that the completion of the
Y2K  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  Y2K  compliance  by
jurisdictional  fixed utilities and

                                       25
<PAGE>
mission-critical  service  providers  such as the PJM (the  Investigation).  The
order required (1) a written response to a list of compliance  program questions
by August 6, 1998 and, (2) all  jurisdictional  fixed utilities be Y2K compliant
by March 31,  1999 or, if a utility  determines  that  mission-critical  systems
cannot be Y2K 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  Y2K  compliance  and  further   defined  Y2K  compliance  as  a
jurisdictional  utility  having all  mission-critical  Y2K 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 would have all mission-critical systems Y2K ready by June 1999. Pursuant
to the formal  investigation on Y2K 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 (1) utilities which have complied with the
PUC's order of July 17, 1998 (the Order);  (2) utilities which have demonstrated
good cause for an extension of time within which they will fully comply with the
Order;  and (3) 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.  The  Company  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  included  July 1, 1999 and  October 1, 1999.  A final
report was sent to the PUC on November 9, 1999 stating that all mission critical
systems were Y2K ready.

         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 Y2K 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 Y2K 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 Y2K ready, or will
be Y2K ready,  by January 1, 2000 with regard to  compliance  with the terms and
conditions of the license(s) and NRC regulations.  On

                                       26
<PAGE>
July 30, 1998, the Company filed its 90-day required written response indicating
that the Company has pursued and is  continuing to pursue a Y2K program which is
similar to that outlined in Nuclear Utility Y2K Readiness, NEI/NUSMG 97.07.

         From November 3 to November 5, 1998, members of the NRC staff conducted
an audit of the  Company's  Y2K  Program  for the  Limerick  Generating  Station
(Limerick),  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 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 Y2K
readiness  and  contingency  planning  site-specific  reviews at all  commercial
nuclear power plants. The NRC performed its site-specific review of Peach Bottom
Atomic Power Station  (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,  the Company filed its completed  response to Generic
Letter 98-01. In the response,  the Company confirmed that with the exception of
five non-safety plant systems,  its Peach Bottom and Limerick are Y2K ready. The
Company advised the NRC that remediation for three of the remaining  systems was
scheduled for  completion by the  conclusion of the fall outage at Peach Bottom.
On October 27, 1999, the Company reported to the NRC that all remaining  systems
were Y2K ready.

         For additional  information  regarding the Y2K 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 3, 9 and 10 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.

                                       27
<PAGE>

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 September 30, 1999, the fair value of these instruments was
$75 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  September  30, 1999 would have
resulted in an aggregate fair value of these interest rate swaps of $111 million
or $36 million,  respectively. If the derivative instruments had been terminated
at September 30, 1999,  these  estimated fair values  represent the amount to be
paid by the counterparties to the Company.

         The  Company's  participation  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.










                                       28
<PAGE>
PART II - OTHER INFORMATION


ITEM 5.  OTHER INFORMATION

         As previously  reported in the 1998 Form 10-K,  the Nuclear  Regulatory
Commission (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. By letters dated  September  17, 1999,  and October 13, 1999,  the Company
notified the NRC of the completion of the Thermo-Lag 330 fire barrier corrective
actions.

         As previously reported in the 1999 Form 10-Q for the quarter ended June
30, 1999,  the Company filed its completed  response to Generic  Letter 98-01 on
June 30, 1999. In the response, the Company confirmed that with the exception of
five  non-safety  plant  systems,  its Peach  Bottom  Atomic  Power  Station and
Limerick were year 2000 ready. On October 27, 1999, the Company  reported to the
NRC that all remaining systems were Y2K ready.

         On  September 8, 1999,  the Company was notified by the National  Labor
Relations  Board  (NLRB) that the Utility  Workers  Union of America  (UWUA) had
filed a petition for a representation election. The UWUA is seeking to represent
selected  production and maintenance  employees in the PECO Energy  Distribution
division (PED). Approximately 1,250 employees in the Operations,  Contractor and
Supply   Management,   Customer   and   Marketing   Services,   Gas  Supply  and
Transportation sections of the PED were eligible to vote.

         On November 9, 1999,  the employees  voted not to be represented by the
UWUA in secret balloting conducted by the NLRB. The PED employees cast 712 votes
for "no union" and 488 votes for UWUA  representation.  The Company and the UWUA
have seven days to file objections to the election.  Absent any  objections,  at
the end of the seven days, the NLRB will certify the results.

         As  previously  reported  in the 1998 Form  10-K,  by notice  issued in
September 1985, the  Environmental  Protection Agency (EPA) notified the Company
that it had been  identified  as a Potentially  Responsible  Party (PRP) for the
costs  associated  with the  cleanup of a site  (Berks  Associates/Douglassville
site) where waste oils  generated  from  Company  operations  were  transported,
treated,  stored and disposed. In August 1991, the EPA filed suit in the Eastern
District  Court against 36 named PRP's,  not  including  the Company,  seeking a
declaration that these PRP's are jointly and severally liable for cleanup of the
Berks Associates/Douglassville site and for costs already expended by the EPA on
the site.  Simultaneously,  the EPA issued an  Administrative  Order against the
same named defendants, not including the Company, which requires the PRP's named
in the  Administrative  Order to commence  cleanup of a portion of the site.  On
September  29, 1992,  the Company and 169 other parties were served with a third
party complaint joining these parties as additional defendants. Subsequently, an
additional 150 parties

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<PAGE>
were joined as  defendants.  A group of  approximately  100 PRP's with allocated
shares of less than 1%, including the Company, formed a negotiating committee to
negotiate a settlement  offer with the EPA. In December 1994, the EPA proposed a
de  minimus  PRP  settlement  which  would  have  required  the  Company  to pay
approximately   $992,000  in  exchange   for  the  EPA   agreeing  not  to  sue.
Subsequently,  the non-de minimus parties successfully  challenged the Record of
Decision  (ROD) remedy.  A ROD amendment was finalized and, on October 27, 1998,
the EPA  settled  with the de  minimus  parties.  Under  the  provisions  of the
settlement,  the Company  would be required to pay  approximately  $522,000  for
liabilities resulting from the government's past and potential future costs. The
Department  of Justice  approved  the  settlement  and on  September 3, 1999 the
Company made the required payment.

         As previously reported in the 1998 Form 10-K, on November 18, 1996, the
Company  received a notice from the EPA that the Company is a PRP at the Malvern
TCE Superfund Site, located in Malvern, Pennsylvania. In April 1998, the Company
was notified of a de minimus  settlement under which the Company was allocated a
total cost of $16,085  for EPA past and future  costs.  On October 6, 1999,  the
Company paid $16,085 as its share of the settlement.

         On September 30, 1999,  Conectiv,  Inc.  (Conectiv)  announced  that it
subsidiaries  Atlantic  City Electric  Company (ACE) and Delmarva  Power & Light
Company  (DPL)  had each  agreed  to sell  one-half  of their  respective  7.51%
interest in Peach Bottom Units 2 and 3,  representing  an aggregate of 164 MW of
capacity to the Company. At closing, ACE and DPL will each receive $5.10 million
plus  7.51% of the net book value of the  nuclear  fuel for their  interests  in
Peach Bottom.  The sales are subject to federal and state regulatory  approvals.
On the same day, Conectiv also announced that ACE and DPL had agreed to sell the
other half of their  interests in Peach Bottom and all of their interests in the
Salem Generating Station to Public Service Electric and Gas Company.


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

         Report,  dated September 14, 1999 reporting  information under "ITEM 5.
                  OTHER  EVENTS"  regarding  AmerGen's  signing an  agreement in
                  principle to acquire Oyster Creek Nuclear Generating  Facility
                  from GPU, Inc.

                                       30
<PAGE>
         Report,  dated September 23, 1999 reporting  information under "ITEM 5.
                  OTHER EVENTS" regarding the joint press release announcing the
                  Company and Unicom entering into a definitive  agreement for a
                  merger of equals.

         Report,  dated September 23, 1999 reporting  information under "ITEM 5.
                  OTHER EVENTS"  regarding  the Company's  Agreement and Plan of
                  Exchange  and Merger  with  Unicom and  Newholdco  Corporation
                  (Newholdco),  a wholly  owned  subsidiary  of the  Company and
                  "ITEM 7. FINANCIAL STATEMENTS, PRO FORMA FINANCIAL INFORMATION
                  AND EXHIBITS" including the Agreement and Plan of Exchange and
                  Merger among the Company, Newholdco and Unicom.

         Report,  dated September 24, 1999 reporting  information under "ITEM 5.
                  OTHER EVENTS"  regarding  presentation to investors  regarding
                  the merger  transaction  between  the  Company  and Unicom and
                  "ITEM 7. FINANCIAL STATEMENTS, PRO FORMA FINANCIAL INFORMATION
                  AND EXHIBITS" regarding the presentation to investors.

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

         Report,  dated September 22, 1999 reporting  information under "ITEM 5.
                  OTHER  EVENTS" and "ITEM 7.  FINANCIAL  STATEMENTS,  PRO FORMA
                  FINANCIAL   INFORMATION  AND  EXHIBITS"  regarding  pro  forma
                  financial information.

         Report,  dated October 19, 1999  reporting  information  under "ITEM 5.
                  OTHER EVENTS" regarding Exelon Infrastructure  Services, Inc.,
                  a subsidiary of the Company,  announcing  the  acquisition  of
                  five utility service companies.

         Report,  dated October 19, 1999  reporting  information  under "ITEM 5.
                  OTHER  EVENTS"  regarding  AmerGen's  accepted  bid to acquire
                  Vermont  Yankee  Nuclear  Power  Station from  Vermont  Yankee
                  Nuclear Power Corporation.





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<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:  November 15, 1999


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