content: 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
  
                                         29
  <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.
  
  
  
  
  
                                         31
  
  <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
  
  
                                         32
metadata_documents: [{"type": "10-Q", "sequence": "1", "secsgml_size_bytes": 108037}]
metadata_filer: {"company-data": {"conformed-name": "PECO ENERGY CO", "cik": "0000078100", "assigned-sic": "4931", "irs-number": "230970240", "state-of-incorporation": "PA", "fiscal-year-end": "1231"}, "filing-values": {"form-type": "10-Q", "act": "34", "file-number": "001-01401", "film-number": "99754649"}, "business-address": {"street1": "2301 MARKET ST", "street2": "P O BOX 8699", "city": "PHILADELPHIA", "state": "PA", "zip": "19101", "phone": "2158414000"}, "former-company": {"former-conformed-name": "PHILADELPHIA ELECTRIC CO", "date-changed": "19920703"}}
text: 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
  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)
  Three Months Ended             Nine Months Ended
                                                                 September 30,                 September 30,
                                                              1999          1998            1999           1998
  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
                                                         ===========   ============    ===========    ===========
  See Notes to Condensed Consolidated Financial Statements.
  
                                         2
  PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
                        CONDENSED CONSOLIDATED BALANCE SHEETS
                                (Millions of Dollars)
  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
                                                            ===========      ===========
  See Notes to Condensed Consolidated Financial Statements.
                              (continued on next page)
  
                                         3
  PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
                        CONDENSED CONSOLIDATED BALANCE SHEETS
                                (Millions of Dollars)
                                     (continued)
  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
                                                                            ==============      ==============
  See Notes to Condensed Consolidated Financial Statements.
  
                                         4
  PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
                   CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
                                     (Unaudited)
                                (Millions of Dollars)
  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
                                                                   ==========       ==========
  See Notes to Condensed Consolidated Financial Statements.
  
                                         5
  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
  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:
  Approximate
                         Face Amount          Bond            Expected                   Final
           Class         (millions)           Rates           Maturity                   Maturity
  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
  (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
  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
  Quarter Ended September 30, 1999 as compared to the Quarter Ended
  September 30, 1998
  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
  (a) EBIT - Earnings Before Interest and Income Taxes.
   (b) Includes $450 million of proceeds from securitization of stranded costs.
  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):
  Three Months Ended                 Nine Months Ended
                                                                    September 30,                      September 30,
                                                                   --------------                     --------------
                                                            1999                 1998             1999               1998
                                                           -----                 -----            -----             -----
  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
                                                           =====                 =====            =====             =====
  9
  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
  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
  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
  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
  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
  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
  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.
  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%)
        ====    ====            ====      ====
  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
  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
  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
  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
  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
  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
  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
  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
  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
  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
  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
  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
  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
  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
  
                                         29
  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
  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.
  
                                         31
  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
  
                                         32