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 June 30, 1999
  
                                         OR
  
            [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
                           SECURITIES EXCHANGE ACT OF 1934
  
                           Commission file number: 1-1401
  
                                 PECO Energy Company
               (Exact name of registrant as specified in its charter)
  
                   Pennsylvania                       23-0970240
            (State or other jurisdiction of         (I.R.S. Employer
            incorporation or organization)          Identification No.)
  
            2301 Market Street, Philadelphia, PA          19103
          (Address of principal executive offices)      (Zip Code)
  
                                   (215) 841-4000
                (Registrant's telephone number, including area code)
  
  
           Indicate by check mark whether the registrant (1) has filed all reports
           required to be filed by Section 13 or 15(d) of the Securities  Exchange
           Act of 1934 during the preceding 12 months (or for such shorter  period
           that the  registrant  was required to file such  reports),  and (2) has
           been subject to such filing requirements for the past 90 days.
  
                                  Yes    X            No  ___
  
           Indicate  the  number of  shares  outstanding  of each of the  issuer's
           classes of common stock as of the latest practicable date:
  
           The Company  had  186,603,406  shares of common  stock  outstanding  on
           August 6, 1999.
  
  <PAGE>
  PART I. FINANCIAL INFORMATION
  
  ITEM 1. FINANCIAL STATEMENTS
  
                    PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
                     CONDENSED CONSOLIDATED STATEMENTS OF INCOME
                                     (Unaudited)
                    (Millions of Dollars, Except Per Share Data)
  
  <TABLE>
  <CAPTION>
                                                           Three Months Ended June 30,         Six Months Ended June 30,
                                                             1999              1998             1999             1998
                                                          -----------      -----------     ------------     ------------
  OPERATING REVENUES
  <S>                                                     <C>                  <C>              <C>              <C>
       Electric                                           $   1,105.4          1,131.8          2,144.3          2,134.8
       Gas                                                       89.0             83.4            306.5            270.6
                                                          -----------      -----------     ------------     ------------
  TOTAL OPERATING REVENUES                                    1,194.4          1,215.2          2,450.8          2,405.4
                                                          -----------      -----------     ------------     ------------
  OPERATING EXPENSES
       Fuel and Energy Interchange                              500.3            360.2            965.4            743.2
       Operating and Maintenance                                338.9            256.0            627.6            539.2
       Depreciation and Amortization                             57.6            160.9            113.9            315.6
       Taxes Other Than Income                                   45.2             71.8            120.5            153.9
                                                          -----------      -----------     ------------     ------------
                                                                942.0            848.9          1,827.4          1,751.9
                                                          -----------      -----------     ------------     ------------
  OPERATING INCOME                                              252.4            366.3            623.4            653.5
                                                          -----------      -----------     ------------     ------------
  
  OTHER INCOME AND DEDUCTIONS
       Interest Expense                                        (113.5)           (86.0)          (187.8)          (171.0)
       Company Obligated Mandatorily Redeemable
            Preferred Securities of a Partnership                (7.4)            (8.2)           (14.8)           (15.9)
       Allowance for Funds Used During Construction               1.7              0.7              2.1              1.3
       Other, Net                                                (4.6)           (26.9)           (46.6)           (39.7)
                                                          -----------      -----------     ------------     ------------
  
  TOTAL OTHER INCOME AND DEDUCTIONS                            (123.8)          (120.4)          (247.1)          (225.3)
                                                          -----------      -----------     ------------     ------------
  
  INCOME BEFORE INCOME TAXES AND
     EXTRAORDINARY ITEM                                         128.6            245.9            376.3            428.2
  
  INCOME TAXES                                                   41.0             94.4            139.0            163.1
                                                          -----------      -----------     ------------     ------------
  
  INCOME BEFORE EXTRAORDINARY ITEM                               87.6            151.5            237.3            265.1
  
  EXTRAORDINARY ITEM - NET OF INCOME TAXES                      (26.7)            --              (26.7)            --
                                                          -----------      -----------     ------------     ------------
  
  NET INCOME                                                     60.9            151.5            210.6            265.1
  
  PREFERRED STOCK DIVIDENDS                                       3.3              3.3              6.6              6.6
                                                          -----------      -----------     ------------     ------------
  
  EARNINGS APPLICABLE TO COMMON STOCK                     $      57.6      $     148.2      $     204.0      $     258.5
                                                          ===========      ===========     ============     ============
  
  AVERAGE SHARES OF COMMON STOCK
       OUTSTANDING (Millions)                                   192.0            222.7            207.6            222.6
                                                          ===========      ===========     ============     ============
  
  BASIC AND DILUTIVE EARNINGS PER
  AVERAGE COMMON SHARES BEFORE EXTRAORDINARY ITEM         $      0.44      $      0.66     $       1.11     $       1.16
  EXTRAORDINARY ITEM                                            (0.14)            --              (0.13)            --
                                                          -----------      -----------     ------------     ------------
  BASIC EARNINGS PER AVERAGE COMMON SHARE                 $      0.30      $      0.66     $       0.98     $       1.16
                                                          ===========      ===========     ============     ============
  
  DIVIDENDS PER AVERAGE COMMON SHARE                      $      0.25      $      0.25     $       0.50     $       0.50
                                                          ===========      ===========     ============     ============
  </TABLE>
  
  See Notes to Condensed Consolidated Financial Statements.
  
  
                                         2
  <PAGE>
                    PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
                        CONDENSED CONSOLIDATED BALANCE SHEETS
                                (Millions of Dollars)
  
  <TABLE>
  <CAPTION>
                                                                               June 30,           December 31,
                                                                                 1999                1998
                                                                              ----------          ----------
                                                                             (Unaudited)
  ASSETS
  
  UTILITY PLANT
  <S>                                                                        <C>                 <C>
  Electric - Transmission & Distribution                                     $   3,890.8         $   3,833.8
  Electric - Generation                                                          1,732.3             1,713.4
  Gas                                                                            1,141.2             1,132.0
  Common                                                                           409.3               407.3
                                                                              ----------          ----------
  
                                                                                 7,173.6             7,086.5
  Less Accumulated Provision for Depreciation                                    3,007.6             2,891.3
                                                                              ----------          ----------
  
                                                                                 4,166.0             4,195.2
  Nuclear Fuel, net                                                                296.7               141.9
  Construction Work in Progress                                                    375.0               272.6
  Leased Property, net                                                               0.5               154.3
                                                                              ----------          ----------
  
                                                                                 4,838.2             4,764.0
                                                                              ----------          ----------
  
  
  CURRENT ASSETS
  Cash and Temporary Cash Investments                                              899.6                48.1
  Accounts Receivable, net
       Customer                                                                    213.1                97.5
       Other                                                                       376.2               213.2
  Inventories, at average cost
       Fossil Fuel                                                                  62.9                92.3
       Materials and Supplies                                                      108.8                82.1
  Deferred Income Taxes                                                              7.7               (14.1)
  Other                                                                            109.0                19.0
                                                                              ----------          ----------
  
                                                                                 1,777.3               538.1
                                                                              ----------          ----------
  
  DEFERRED DEBITS AND OTHER ASSETS
  Competitive Transition Charge                                                  5,274.6             5,274.6
  Recoverable Deferred Income Taxes                                                609.2               614.4
  Deferred Non-Pension Postretirement Benefits Costs                                87.7                90.9
  Investments                                                                      554.8               538.1
  Loss on Reacquired Debt                                                           73.9                77.2
  Other                                                                            131.0               107.1
                                                                              ----------          ----------
  
                                                                                 6,731.2             6,702.3
                                                                              ----------          ----------
  
  TOTAL                                                                       $ 13,346.7          $ 12,004.4
                                                                              ==========          ==========
  </TABLE>
  
              See Notes to Condensed Consolidated Financial Statements.
                              (continued on next page)
  
                                         3
  <PAGE>
                    PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
                        CONDENSED CONSOLIDATED BALANCE SHEETS
                                (Millions of Dollars)
                                     (continued)
  <TABLE>
  <CAPTION>
                                                                              June 30,          December 31,
                                                                                1999                1998
                                                                              ----------          ----------
                                                                             (Unaudited)
  CAPITALIZATION AND LIABILITIES
  
  CAPITALIZATION
  Common Shareholders' Equity
  <S>                                                                       <C>                 <C>
       Common Stock (No Par)                                                $    3,616.7        $    3,589.0
       Other Paid-In Capital                                                         1.2                 1.2
       Accumulated Deficit                                                        (422.5)             (532.9)
       Treasury Stock                                                           (1,507.3)                 --
  Preferred and Preference Stock
       Without Mandatory Redemption                                                137.5               137.5
       With Mandatory Redemption                                                    92.7                92.7
  Company Obligated Mandatorily Redeemable
       Preferred Securities of a Partnership                                       340.4               349.4
  Long-Term Debt                                                                 6,092.2             2,919.6
                                                                              ----------          ----------
  
                                                                                 8,350.9             6,556.5
                                                                              ----------          ----------
  
  CURRENT LIABILITIES
  Notes Payable, Bank                                                              226.0               525.0
  Long-Term Debt Due Within One Year                                               146.1               361.5
  Capital Lease Obligations Due Within One Year                                     --                  69.0
  Accounts Payable                                                                 357.5               316.2
  Taxes Accrued                                                                    187.4               170.5
  Interest Accrued                                                                 104.9                61.5
  Deferred Energy Costs - Gas                                                       26.3               (29.9)
  Other                                                                            235.6               217.4
                                                                              ----------          ----------
  
                                                                                 1,283.8             1,691.2
                                                                              ----------          ----------
  
  DEFERRED CREDITS AND OTHER LIABILITIES
  Capital Lease Obligations                                                          0.5                85.3
  Deferred Income Taxes                                                          2,355.3             2,376.9
  Unamortized Investment Tax Credits                                               292.8               300.0
  Pension Obligation                                                               219.3               219.3
  Non-Pension Postretirement Benefits Obligation                                   436.1               421.1
  Other                                                                            408.0               354.1
                                                                              ----------          ----------
  
                                                                                 3,712.0             3,756.7
                                                                              ----------          ----------
  
  COMMITMENTS AND CONTINGENCIES (NOTE 8)
  
  TOTAL                                                                      $  13,346.7          $ 12,004.4
                                                                             ===========          ==========
  </TABLE>
  
              See Notes to Condensed Consolidated Financial Statements.
  
                                         4
  <PAGE>
                    PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
                   CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
                                     (Unaudited)
                                (Millions of Dollars)
  <TABLE>
  <CAPTION>
                                                                       Six Months Ended June 30,
                                                                         1999             1998
                                                                     ----------         --------
  CASH FLOWS FROM OPERATING ACTIVITIES
  <S>                                                                <C>                <C>
  NET INCOME                                                         $    210.6         $  265.1
  EXTRAORDINARY ITEM, NET OF INCOME TAXES                                  26.7             --
                                                                     ----------         --------
  
  INCOME BEFORE EXTRAORDINARY ITEM                                        237.3            265.1
  
  Adjustments to Reconcile Net Income to Net Cash
       Provided by Operating Activities:
  Depreciation and Amortization                                           149.4            343.0
  Deferred Income Taxes                                                   (38.2)           (29.3)
  Amortization of Investment Tax Credits                                   (7.2)            (9.0)
  Deferred Energy Costs                                                    56.1             27.1
  Changes in Working Capital:
       Accounts Receivable                                               (278.5)           (87.1)
       Inventories                                                          2.7              9.0
       Accounts Payable                                                    41.3            (11.3)
       Other Current Assets and Liabilities                                14.4            (68.8)
  Other Items Affecting Operations                                         74.4             71.3
                                                                     ----------         --------
  
  
  CASH FLOWS PROVIDED BY OPERATING ACTIVITIES                             251.7            510.0
                                                                     ----------         --------
  
  
  CASH FLOWS FROM INVESTING ACTIVITIES
  
  Investment in Plant                                                    (244.4)          (229.1)
  Increase in Investments                                                 (35.0)           (35.8)
                                                                     ----------         --------
  
  
  NET CASH FLOWS USED IN INVESTING ACTIVITIES                            (279.4)          (264.9)
                                                                     ----------         --------
  
  
  CASH FLOWS FROM FINANCING ACTIVITIES
  
  Issuance of Long-Term Debt                                            4,000.0              6.4
  Common Stock Repurchase                                              (1,507.3)            --
  Debt Repayments                                                      (1,202.5)           (96.8)
  Change in Short-Term Debt                                              (299.0)           (55.5)
  Dividends on Preferred and Common Stock                                (109.9)          (117.8)
  Issuance of Company Obligated Mandatorily
       Redeemable Preferred Securities of a Partnership                    --               78.1
  Issuance of Common Stock                                                 14.0              9.3
  Other Items Affecting Financing                                         (16.1)             3.1
                                                                     ----------         --------
  
  
  NET CASH FLOWS PROVIDED BY (USED IN) FINANCING ACTIVITIES               879.2           (173.2)
                                                                     ----------         --------
  
  
  INCREASE IN CASH AND CASH EQUIVALENTS                                   851.5             71.9
                                                                     ----------         --------
  
  
  CASH AND CASH EQUIVALENTS AT BEGINNING OF  PERIOD                        48.1             33.4
                                                                     ----------         --------
  
  
  CASH AND CASH EQUIVALENTS AT END OF  PERIOD                        $    899.6         $  105.3
                                                                     ==========         ========
  </TABLE>
  
              See Notes to Condensed Consolidated Financial Statements.
  
                                         5
  <PAGE>
                    PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
                NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
  
  1.       BASIS OF PRESENTATION
           The accompanying condensed consolidated financial statements as of June
  30, 1999 and for the three and six months then ended are unaudited,  but include
  all adjustments  that PECO Energy Company  (Company)  considers  necessary for a
  fair presentation of such financial statements. All adjustments are of a normal,
  recurring nature.  The year-end condensed  consolidated  balance sheet data were
  derived from audited  financial  statements  but do not include all  disclosures
  required by generally accepted accounting principles. Certain prior-year amounts
  have been reclassified for comparative  purposes.  These notes should be read in
  conjunction with the Notes to Consolidated Financial Statements in the Company's
  1998 Annual Report to  Shareholders,  which are incorporated by reference in the
  Company's Annual Report on Form 10-K for the year ended December 31, 1998.
  
  
  2.       TRANSITION BONDS
           On March 25, 1999, PECO Energy  Transition Trust (PETT), an independent
  statutory business trust organized under the laws of Delaware and a wholly owned
  subsidiary  of the  Company,  issued $4 billion  aggregate  principal  amount of
  Transition  Bonds  (Transition  Bonds) to  securitize a portion of the Company's
  authorized  stranded cost recovery.  The Transition Bonds are solely obligations
  of PETT, secured by Intangible  Transition  Property sold by the Company to PETT
  concurrently  with the  issuance  of the  Transition  Bonds  and  certain  other
  collateral related thereto.
  
           The terms of the Transition Bonds are as follows:
  <TABLE>
  <CAPTION>
                         Approximate
                         Face Amount          Bond            Expected                   Final
           Class         (millions)           Rates           Maturity                   Maturity
  <S>                   <C>                  <C>              <C>                      <C>
           A-1           $244.5               5.48%           March 1, 2001              March 1, 2003
           A-2           $275.4               5.63%           March 1, 2003              March 1, 2005
           A-3           $667.0               5.18% (a)       March 1, 2004              March 1, 2006
           A-4           $458.5               5.80%           March 1, 2005              March 1, 2007
           A-5           $464.6               5.26% (a)       September 1, 2007          March 1, 2009
           A-6           $993.4               6.05%           March 1, 2007              March 1, 2009
           A-7           $896.7               6.13%           September 1, 2008          March 1, 2009
  </TABLE>
  
           (a) The Class A-3 and A-5 Transition  Bonds earn interest at a floating
           rate.  The rates  provided for each such class above are as of June 30,
           1999.
  
  
                                         6
  <PAGE>
  
  
           The  Company  entered  into  treasury  forwards  and  forward  starting
  interest  rate  swaps to  manage  interest  rate  exposure  associated  with the
  anticipated  issuance of Transition  Bonds. On March 18, 1999, these instruments
  were settled with net proceeds to the Company of approximately $80 million which
  were deferred and are being amortized over the life of the Transition Bonds as a
  reduction of interest  expense,  consistent with the Company's hedge  accounting
  policy.
  
           The Company has entered  into  interest  rate swaps to manage  interest
  rate  exposure  associated  with the  issuance  of two  floating  rate series of
  Transition  Bonds. At June 30, 1999, the fair value of these instruments was $52
  million based on the present value difference between the contracted rate (i.e.,
  hedged rate) and the market rates at that date.  A  hypothetical  50 basis point
  increase or  decrease in the spot yield at June 30, 1999 would have  resulted in
  an aggregate  fair value of these  interest rate swaps of $91.2 million or $10.7
  million, respectively. If the derivative instruments had been terminated at June
  30, 1999,  these  estimated  fair values  represent the amount to be paid by the
  counterparties to the Company.
  
           The net proceeds to the Company from the securitization of a portion of
  its allowed  stranded cost recovery,  after payment of fees and expenses and the
  capitalization of PETT, were approximately $3.95 billion. In accordance with the
  provisions  of the  Pennsylvania  Electricity  Generation  Customer  Choice  and
  Competition  Act, the Company is utilizing these proceeds  principally to reduce
  its  stranded  costs and related  capitalization.  Through  June 30,  1999,  the
  Company  utilized the net proceeds to repurchase  38.7 million  shares of Common
  Stock for an aggregate purchase price of $1.507 billion; to retire: $811 million
  of First Mortgage  Bonds,  a $400 million term loan,  $208 million of commercial
  paper, $150 million of accounts receivable  financing and a $139 million capital
  lease  obligation;  to  repurchase $9 million of Company  Obligated  Mandatorily
  Redeemable  Preferred  Securities  of a  Partnership  (COMRPS);  and to pay  $25
  million of debt issuance costs.  The remaining  proceeds of  approximately  $750
  million are  included in cash at June 30, 1999.  In addition,  on July 30, 1999,
  the Company  redeemed  $212  million of COMRPS.  On August 2, 1999,  the Company
  retired $37 million of Mandatorily  Redeemable  Preferred  Stock pursuant to the
  sinking fund requirements of those securities.
  
           In the second  quarter of 1999, the Company  incurred an  extraordinary
  charge of $26.7 million,  net of tax,  consisting of prepayment premiums and the
  write-off of unamortized  deferred  financing  costs  associated  with the early
  retirement of debt.
  
  
  3.   SEGMENT INFORMATION
           The Company is primarily a vertically  integrated  public  utility that
  provides  retail  electric  and  natural  gas  service  to  the  public  in  its
  traditional  service territory and retail electric generation service throughout
  Pennsylvania  pursuant to Pennsylvania's  Customer Choice Program. The Company's
  management  has  historically  managed  the Company as a  vertically  integrated
  entity by analyzing its results of operations  on a  consolidated  basis with an
  emphasis on electric and gas operations.
  
            During the first quarter of 1999,  the Company  completed the redesign
  of its internal  reporting  structure to separate its distribution,  generation,
  
  
                                         7
  <PAGE>
  
  and  ventures   operations  into  business  units  and  provide   financial  and
  operational  data  on  the  same  basis  to  senior  management.  The  Company's
  distribution  business unit includes its electric  transmission and distribution
  services,   regulated  retail  sales  of  generation  services  and  retail  gas
  businesses. The Company's generation business unit includes the operation of its
  generation assets and its power marketing group. The Company's ventures business
  unit includes its unregulated  retail energy supplier,  infrastructure  services
  business and its telecommunications equity investments.
  
           During the second  quarter of 1999,  the  Company  further  revised the
  internal  reporting  structure to include its unregulated retail energy supplier
  with the  generation  business  unit to more  efficiently  manage the  Company's
  overall energy supply requirements.  Accordingly,  the results of operations and
  assets of the unregulated  retail energy supplier are included in the generation
  business unit for all periods presented.
  
           The  Company's  segment  information  as of and for the  three  and six
  months ended June 30, 1999 as compared to the same 1998 period is as follows (in
  millions of dollars):
  
  Quarter Ended June 30, 1999 as compared to the quarter ended June 30, 1998
  <TABLE>
  <CAPTION>
  <S>                 <C>                 <C>                 <C>            <C>              <C>                <C>
                                                                                              Intersegment
                      Distribution        Generation         Ventures       Corporate           Revenues         Consolidated
                      ------------        ----------         --------       ---------           --------         ------------
  Revenues:
      1999               $734.0             $653.2             $   .6           $    -          $(193.4)           $1,194.4
      1998               $905.5             $547.7             $   .7           $    -          $(238.7)           $1,215.2
  EBIT (a):
      1999               $298.2             $ 11.1            $( 15.1)         $( 44.7)                            $  249.5
      1998               $356.0             $ 61.0            $( 35.8)         $( 41.1)                            $  340.1
  
  Six Months Ended June 30, 1999 as compared to six months ended June 30, 1998
  
  Revenues:
      1999               $1,646.5           $1,197.9           $   1.2          $ -             $(394.8)           $2,450.8
      1998               $1,854.3           $1,029.6           $   1.3          $ -             $(479.8)           $2,405.4
  EBIT (a):
      1999               $655.7             $ 41.0(b)         $( 36.0)         $( 81.8)                            $  578.9
      1998               $663.5             $ 99.0            $( 59.5)         $( 87.9)                            $  615.1
  Total Assets:
      1999              $10,810.8(c)       $1,868.5            $240.2          $427.2                              $13,346.7
      1998              $ 9,723.6          $1,680.6            $216.1          $384.1                              $12,004.4
  <FN>
   (a) EBIT - Earnings Before Interest and Income Taxes.
   (b) Includes an $11.8 million reserve related to the Grays Ferry power purchase
   agreement and $14.6 million related to the write-off of the investment in Grays
   Ferry in connection with the settlement of litigation.
   (c) Includes $750 million of proceeds from securitization of stranded costs.
  </FN>
  </TABLE>
  
  
  
  
                                         8
  <PAGE>
  
  4.       EARNINGS PER SHARE
           Diluted  earnings per average  common share is  calculated  by dividing
  earnings  applicable  to common  stock by the  average  shares  of common  stock
  outstanding  after giving effect to stock options,  issuable under the Company's
  stock option plans,  considered  to be dilutive  common stock  equivalents.  The
  following  table  shows  the  effect  of the stock  options  issuable  under the
  Company's stock option plans on the average number of shares used in calculating
  diluted earnings per average common share (in millions of shares):
  <TABLE>
  <CAPTION>
                                                              Three Months Ended                   Six Months Ended
                                                                   June 30,                             June 30,
                                                            1999                  1998            1999               1998
                                                           -----                 -----            -----             -----
  <S>                                                      <C>                   <C>              <C>               <C>
  Average Common Shares Outstanding                        192.0                 222.7            207.6             222.6
  
  Assumed Conversion of Stock Options                        1.5                    .7              1.5                .7
                                                           -----                 -----            -----             -----
  
  Potential Average Dilutive
    Common Shares Outstanding                              193.5                 223.4            209.1             223.3
                                                           =====                 =====            =====             =====
  </TABLE>
  
  5.       SALES OF ACCOUNTS RECEIVABLE
           The  Company is party to an  agreement  with a  financial  institution,
  under which it can sell or finance with limited recourse an undivided  interest,
  adjusted daily, in up to $275 million of designated  accounts  receivable  until
  November 2000. At June 30, 1999, the Company had sold a $275 million interest in
  accounts  receivable,   consisting  of  a  $232  million  interest  in  accounts
  receivable which the Company accounts for as a sale under Statement of Financial
  Accounting  Standards (SFAS) No. 125, "Accounting for Transfers and Servicing of
  Financial Assets and  Extinguishment of Liabilities," and a $43 million interest
  in special agreement accounts  receivable which are accounted for as a long-term
  note  payable.  The  Company  retains  the  servicing  responsibility  for these
  receivables.  The  agreement  requires  the Company to maintain the $275 million
  interest,  which,  if not met,  requires the Company to deposit cash in order to
  satisfy such requirements. The Company, at June 30, 1999, met such requirements.
  At June 30, 1999, the average annual  service-charge  rate,  computed on a daily
  basis on the portion of the accounts receivable sold but not yet collected,  was
  4.90%.
  
  
  6.       AMERGEN ENERGY COMPANY
           On April 15, 1999,  AmerGen Energy  Company,  LLC (AmerGen),  the joint
  venture between the Company and British Energy, plc (British Energy),  announced
  an interim  agreement to purchase the Clinton  Nuclear Power  Station  (Clinton)
  from  Illinois  Power (IP), a subsidiary  of Illinova  Corporation.  On June 30,
  1999,  AmerGen and British  Energy  signed a  definitive  agreement  to purchase
  Clinton from IP.  AmerGen has entered  into  agreements  to purchase  Three Mile
  Island Unit No.1  Nuclear  Generating  Facility,  Nine Mile Point Unit 1 Nuclear
  Generating  Facility  and 59% of  Nine  Mile  Point  Unit 2  Nuclear  Generating
  Facility.  In  addition,  the  Company  and IP  amended  the  January  15,  1998
  Management Agreement, providing for the provision of certain management services
  by the  Company  to IP in support  of  Clinton's  outage  recovery  efforts  and
  operations.
  
                                         9
  <PAGE>
  
     7.    CLINTON NUCLEAR POWER STATION
           Under the Amended  Management  Agreement,  effective April 1, 1999, the
  Company is responsible  for the payment of all direct  operating and maintenance
  (O&M)  costs and  direct  capital  costs  incurred  by IP and  allocable  to the
  operation of Clinton.  IP will  continue to pay  indirect  costs such as pension
  benefits,  payroll taxes and property  taxes.  Following the restart of Clinton,
  which  occurred on June 2, 1999,  and through  December 31, 1999, the Company is
  selling 80% of the output of Clinton to IP. The  remaining  output is being sold
  by the Company in the  wholesale  market.  Under a separate  agreement  with the
  Company,  British  Energy  has  agreed to share  50% of the  costs and  revenues
  associated with the Amended Management Agreement. In the second quarter of 1999,
  the Company  recognized  $14 million of revenue from sales to IP and $25 million
  of O&M expenses related to Clinton.
  
  
  8.       COMMITMENTS AND CONTINGENCIES
           For information  regarding the Company's capital  commitments,  nuclear
  insurance,  nuclear  decommissioning and spent fuel storage, energy commitments,
  environmental  issues  and  litigation,  see  note 5 of  Notes  to  Consolidated
  Financial Statements for the year ended December 31, 1998.
  
           At June 30,  1999,  the Company had entered into  long-term  agreements
  with  unaffiliated  utilities to purchase  transmission  rights.  These purchase
  commitments  result in  obligations  of  approximately  $50 million in 1999, $88
  million in 2000,  $51 million in 2001,  and $41 million in 2002,  $36 million in
  2003 and $97 million thereafter.
  
           The Company has identified 28 sites where former manufactured gas plant
  (MGP) activities have or may have resulted in actual site  contamination.  As of
  June  30,  1999,   the  Company  had  accrued  $59  million  for   environmental
  investigation and remediation costs, including $33 million for MGP investigation
  and remediation that currently can be reasonably  estimated.  The Company cannot
  predict  whether it will incur  other  significant  liabilities  for  additional
  investigation  and remediation  costs at these or additional sites identified by
  the Company, environmental agencies or others, or whether all such costs will be
  recoverable from third parties.
  
           On April 23, 1999, the Company and Grays Ferry Cogeneration Partnership
  (Grays Ferry)  entered into a final  settlement of  litigation.  The  settlement
  resulted in a restructuring of the power purchase  agreement between the Company
  and Grays Ferry.  The  settlement  also required the Company to  contribute  its
  interest in the partnership to the remaining partners.  Accordingly, the Company
  recorded  a  charge  to  earnings  of  $14.6  million  for the  transfer  of its
  partnership  interest  and a  reserve  of $11.8  million  related  to the  power
  purchase agreement. The charge for the partnership interest transfer is recorded
  in Other  Income  and  Deductions  and the  reserve  related  to power  purchase
  agreement is recorded in Fuel and Energy  Interchange  Expense on the  Company's
  Statement of Income for the six months ended June 30, 1999. The settlement  also
  resolved  the  litigation  with  Westinghouse  Power  Generation  and The  Chase
  Manhattan Bank.
  
  
                                         10
  <PAGE>
  
  9.       NEW ACCOUNTING PRONOUNCEMENTS
           In June 1998, the Financial  Accounting  Standards  Board (FASB) issued
  SFAS No. 133,  "Accounting for Derivative  Instruments and Hedging  Activities,"
  (SFAS No. 133) to establish  accounting and reporting standards for derivatives.
  The new  standard  requires  recognizing  all  derivatives  as either  assets or
  liabilities  on the  balance  sheet  at  their  fair  value  and  specifies  the
  accounting  for changes in fair value  depending  upon the  intended  use of the
  derivative.  In June  1999,  the  FASB  issued  SFAS  No.  137  "Accounting  for
  Derivative  Instruments and Hedging  Activities - Deferral of the Effective Date
  of FASB  Statement No. 133," (SFAS No. 137) which delayed the effective date for
  SFAS No. 133 until  fiscal  years  beginning  after June 15,  2000.  The Company
  expects to adopt SFAS No. 133 in the first  quarter of 2001.  The  Company is in
  the  process  of  evaluating  the  impact  of  SFAS  No.  133 on  its  financial
  statements.
  
           In November 1998, the FASB's  Emerging  Issues Task Force (EITF) issued
  EITF  98-10,  "Accounting  for  Contracts  Involved  in Energy  Trading and Risk
  Management Activities." EITF 98-10 outlines attributes that may be indicative of
  an energy  trading  operation and gives further  guidance on the  accounting for
  contracts entered into by an energy trading operation.  This accounting guidance
  requires  mark-to-market  accounting  for  contracts  considered to be a trading
  activity. EITF 98-10 is applicable for fiscal years beginning after December 15,
  1998 with any impact recorded as a cumulative effect adjustment through retained
  earnings at the date of adoption.
  
           The Company's wholesale  marketing  operations enter into long-term and
  short-term  commitments to purchase and sell energy and energy-related  products
  with the intent and ability to deliver or take  delivery.  The  objective of the
  long-term  commitments is to establish a generation base that allows the Company
  to meet the  physical  supply and demand  requirements  of a national  wholesale
  electric marketplace through scheduled,  real-time delivery of electricity.  The
  Company utilizes  short-term energy  commitments and contracts,  entered into in
  the  over-the-counter  market,  to  economically  hedge seasonal and operational
  risks associated with peak demand periods and generation plant outages.
  
           The Company  reviewed  the  criteria  indicative  of an energy  trading
  operation  as outlined in EITF 98-10  against the  objectives  and intent of the
  Company's wholesale marketing operation's activities. The Company concluded that
  none of the  activities of its marketing  operation are trading  activities  and
  therefore  these  activities  are not  subject to EITF  98-10 or  mark-to-market
  accounting.
  
           The Company  records  revenues and expenses  associated with the energy
  commitments   at  the  time  the   underlying   physical   transaction   closes.
  Additionally,  the Company evaluates its energy commitments for impairment based
  on the lower of cost or market.  At June 30, 1999, the Company concluded that no
  energy commitments were impaired.
  
  
                                         11
  <PAGE>
  
  ITEM 2.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
  RESULTS OF OPERATIONS
  
  GENERAL
  
           Retail   competition   for  electric   generation   services  began  in
  Pennsylvania on January 1, 1999. As of January 2, 1999, two-thirds of each class
  of the Company's retail electric customers in its traditional  service territory
  have a right to choose their generation  suppliers.  Effective  January 2, 2000,
  all of the  Company's  retail  electric  customers  in its  traditional  service
  territory will have the right to choose their generation suppliers.  At June 30,
  1999,   approximately  239,000  customers  representing  15%  of  the  Company's
  residential customers, 25% of its commercial customers and 58% of its industrial
  customers had selected an alternate  energy  supplier.  As of that date,  Exelon
  Energy,  the Company's  alternative  energy  supplier,  was  providing  electric
  generation service to approximately  141,000 business and residential  customers
  located throughout Pennsylvania.
  
           Effective  January 1, 1999,  the Company  reduced  its retail  electric
  rates for all customers by 8%. On that date,  the Company began  recovering  its
  stranded costs through the collection of competitive transition charges from all
  customers.  On March 25, 1999,  PECO Energy  Transition  Trust (PETT),  a wholly
  owned  subsidiary  of the Company,  issued $4 billion of PECO Energy  Transition
  Trust  Transition  Bonds to securitize a portion of the Company's  stranded cost
  recovery.  In accordance with the terms of the  Competition  Act, the Company is
  utilizing the proceeds from the issuance of the Transition Bonds  principally to
  reduce stranded costs and capitalization.
  
           The Company currently  estimates that the impact of additional interest
  expense  associated  with the  Transition  Bonds  partially  offset by  interest
  savings  related to higher cost debt  retired  with  Transition  Bond  proceeds,
  combined  with the  anticipated  reduction  in  common  equity,  will  result in
  earnings  per share  benefits of  approximately  $.15 and $.50 in 1999 and 2000,
  respectively.  These  estimated  earnings per share could change and are largely
  dependent upon the timing and price of common stock  repurchases and anticipated
  net income available to common stock.
  
           The Company  expects  that  competition  for both retail and  wholesale
  generation services will substantially  affect its future results of operations.
  See "Management's  Discussion and Analysis of Financial Condition and Results of
  Operations - Outlook,"  incorporated by reference in the Company's Annual Report
  on Form 10-K for the year ended December 31, 1998.
  
           The   Company's   internal   reporting   structure   consists   of  its
  distribution,  generation,  and ventures operations.  The Company's distribution
  business  unit includes its electric  transmission  and  distribution  services,
  regulated  retail sales of generation  services and retail gas  businesses.  The
  Company's  generation  business unit  includes the  operation of its  generation
  assets,  its power marketing group and its unregulated  retail energy  supplier.
  The  Company's  ventures  business  unit  includes its  infrastructure  services
  business and its telecommunications equity investments.
  
  
                                         12
  <PAGE>
  
  
  RESULTS OF OPERATIONS
  
           The Company's Condensed Consolidated Statements of Income for the three
  and six months ended June 30, 1998 reflect the  reclassification  of the results
  of operations of Exelon Energy, from Other Income and Deductions.
  
           Under its  Amended  Management  Agreement  with  Illinois  Power  (IP),
  effective  April 1, 1999,  the  Company is  responsible  for the  payment of all
  direct  operating and maintenance  (O&M) costs and direct capital costs incurred
  by IP and allocable to the operation of Clinton Nuclear Power Station (Clinton).
  IP will continue to pay indirect costs such as pension  benefits,  payroll taxes
  and property  taxes.  Following the restart of Clinton,  which  occurred on June
  2,1999,  and through December 31, 1999, the Company is selling 80% of the output
  of  Clinton  to IP. The  remaining  output is being  sold by the  Company in the
  wholesale market.  Under a separate  agreement with the Company,  British Energy
  has agreed to share 50% of the costs and  revenues  associated  with the Amended
  Management Agreement.
  
  <TABLE>
  <CAPTION>
  Revenue and Expense Items as a
  Percentage of Total Operating
  Revenues                                                                 Percentage Dollar Changes
                                                                                 1999 vs. 1998
          Quarter           Six Months                                       Quarter        Six Months
           Ended               Ended                                          Ended           Ended
          June 30,            June 30,                                       June 30,       June 30,
      1999      1998        1999   1998
  <S>  <C>       <C>         <C>    <C>                                        <C>           <C>
       93%       93%         87%    89%      Electric                          (2%)           --%
        7%        7%         13%    11%      Gas                                7%            13%
      ----      ----        ----   ----
      100%      100%        100%   100%      Total Operating Revenues          (2%)            2%
      ----      ----        ----   ----
  
       42%       30%         39%    31%      Fuel and Energy Interchange       39%            30%
       28%       21%         26%    22%      Operating and Maintenance         32%            16%
        5%       13%          5%    13%      Depreciation and Amortization    (64%)          (64%)
        4%        6%          5%     6%      Taxes Other Than Income          (37%)          (22%)
      ----      ----        ----   ----
       79%       70%         75%    72%      Total Operating Expenses          11%             4%
      ----      ----        ----   ----
  
       21%       30%         25%    28%      Operating Income                 (31%)           (5%)
      ----      ----        ----   ----
  
      (10%)      (8%)        (8%)   (8%)     Interest Charges                  28%             8%
      ( 1%)      (2%)        (2%)   (2%)     Other Income and Deductions      (83%)           17%
      ----      ----        ----   ----
  
                                             Income Before Income Taxes and
       10%       20%         15%    18%        Extraordinary Item             (48%)          (12%)
        3%        8%          6%     7%      Income Taxes                     (57%)          (15%)
      ----      ----        ----   ----
        7%       12%          9%    11%      Income Before Extraordinary Item
       (2%)       --         (1%)    --      Extraordinary Item               100%            --%
      ----      ----        ----   ----
        5%       12%          8%    11%   Net Income                          (60%)          (21%)
      ====      ====        ====   ====
  </TABLE>
  
  
  
  
                                         13
  <PAGE>
  
  Second Quarter 1999 Compared To Second Quarter 1998
  Operating Revenues
           Electric revenues  decreased $26 million,  or 2%, for the quarter ended
  June 30, 1999  compared to the same 1998  period.  The  decrease  was  primarily
  attributable  to lower  revenues  from the  distribution  business  unit of $176
  million partially offset by higher revenues from the generation business unit of
  $150 million. The decrease from the distribution  business unit was attributable
  to $136  million  as a result of lower  volume  associated  with the  effects of
  competition,  $65  million  related to the 8%  across-the-board  rate  reduction
  mandated by the Final  Restructuring  Order and $12 million related to decreased
  sales  volume  from  milder  weather  conditions  as  compared to the prior year
  comparable  period.  These decreases were partially offset by $37 million of PJM
  Interconnection,  LLC (PJM) network transmission service revenue which commenced
  April 1, 1998.  PJM network  transmission  service  revenues  and  charges  were
  recorded in the generation business unit in 1998 but are being recognized by the
  distribution  business unit in 1999 as a result of the Federal Energy Regulatory
  Commission  approval  of  the  PJM  Regional   Transmission  Owners'  rate  case
  settlements. Stranded cost recovery is included in the Company's retail electric
  rates beginning January 1, 1999. The increase from the generation  business unit
  was attributable to $117 million from increased volume in Pennsylvania resulting
  from the sale of  competitive  electric  generation  services by Exelon  Energy,
  increased  wholesale  revenues  of $58  million  from the  marketing  of  excess
  generation  capacity as a result of retail  competition and $14 million from the
  sale of generation  from Clinton to IP,  partially  offset by $39 million of PJM
  network transmission service revenue in the comparable period.
  
           Gas revenues  increased $6 million,  or 7%, for the quarter  ended June
  30,  1999  compared  to  the  same  1998  period.  The  increase  was  primarily
  attributable  to $4 million from increased  volume as a result of cooler weather
  conditions in the beginning of the quarter and $2 million from increased  volume
  from new and existing customers.
  
  Fuel and Energy Interchange Expense
           Fuel and energy interchange expense increased $140 million, or 39%, for
  the  quarter  ended  June 30,  1999  compared  to the  same  1998  period.  As a
  percentage of revenue, fuel and interchange expenses were 42% as compared to 30%
  in the comparable prior year period. These increases were attributable to higher
  fuel and energy  interchange  expenses  associated with the generation  business
  unit of $83 million  and the  distribution  business  unit of $57  million.  The
  increase from the generation  business unit was primarily  attributable  to $129
  million related to increased  volume from Exelon Energy sales,  partially offset
  by lower PJM network  transmission service charges of $39 million and $3 million
  of fuel  savings  associated  with the  full  return  to  service  of the  Salem
  Generating  Station  (Salem) in April 1998 which  decreased the need to purchase
  power to replace the output from these units. The increase from the distribution
  business  unit was  attributable  to $24  million  of PJM  network  transmission
  service charges,  $46 million of purchases in the spot market and $10 million of
  additional  gas  purchases as a result of higher volume  associated  with cooler
  weather  early  in  the  quarter  and  additional  volume  to new  and  existing
  customers.  These  increases were partially  offset by $23 million of lower fuel
  costs primarily as a result of lower volume associated with Customer Choice.
  
  
  
                                         14
  <PAGE>
  
  Operating and Maintenance Expense
           Operating and maintenance (O&M) expense  increased $83 million,  or 32%
  for the quarter  ended June 30,  1999  compared  to the same 1998  period.  As a
  percentage of revenue,  operating and maintenance  expenses were 28% as compared
  to 21% in the comparable prior year period.  The generation  business unit's O&M
  expenses increased $58 million as a result of $25 million related to the revised
  Clinton  management  agreement,  $15 million associated with the Salem inventory
  write-off  and true-up of 1998  reimbursement  of  joint-owner  expenses and $15
  million related to the growth of unregulated  retail sales of  electricity.  The
  distribution unit's O&M expenses increased approximately $22 million as a result
  of additional  marketing expenses and expenses  associated with Customer Choice.
  In addition,  the Company incurred additional costs of approximately $11 million
  related to nuclear property  insurance and $4 million  associated with Year 2000
  remediation expenditures,  partially offset by $10 million of pension credits as
  a result of the performance of the investments in the Company's pension plan.
  
  Depreciation and Amortization Expense
           Depreciation and amortization  expense decreased $103 million,  or 64%,
  for the quarter  ended June 30,  1999  compared  to the same 1998  period.  As a
  percentage of revenue,  depreciation and amortization expense was 5% as compared
  to 13% in the comparable prior year period. The decrease was associated with the
  December  1997  restructuring  charge  through  which the  Company  wrote down a
  significant portion of its generating plant and regulatory assets. In connection
  with this restructuring charge, the Company reduced generation-related assets by
  $8.4  billion,   established  a  regulatory  asset,  Deferred  Generation  Costs
  Recoverable in Current Rates of $424 million, which was fully amortized in 1998,
  and established an additional  regulatory asset,  Competitive  Transition Charge
  (CTC) of $5.26 billion  which will begin to be amortized in accordance  with the
  terms of the Final Restructuring Order in 2000. For additional information,  see
  "PART I, ITEM 1. - BUSINESS -  Deregulation  and Rate Matters," in the Company's
  1998 Annual Report on Form 10-K.
  
  Taxes Other Than Income
           Taxes other than income decreased $27 million,  or 37%, for the quarter
  ended  June 30,  1999  compared  to the same 1998  period.  As a  percentage  of
  revenue,  taxes other than income were 4%, as compared to 6%, in the  comparable
  prior year  period.  The decrease was  primarily  attributable  to a $26 million
  credit related to an adjustment to the Company's  Pennsylvania capital stock tax
  base as a result of the 1997  restructuring  charge and lower gross receipts tax
  of $3 million associated with lower retail electric and gas sales.
  
  Interest Charges
           Interest charges consist of interest expense,  distributions on Company
  Obligated Mandatorily  Redeemable Preferred Securities of a Partnership (COMPRS)
  and  Allowance  for Funds Used During  Construction  (AFUDC).  Interest  charges
  increased  $26 million,  or 28%, for the quarter ended June 30, 1999 compared to
  the same 1998 period.  As a percentage of revenue,  interest charges were 10% as
  compared to 8% in the comparable  prior year period.  The increase was primarily
  attributable  to  interest on the  Transition  Bonds of $60  million,  partially
  offset by the Company's  ongoing program to reduce and/or refinance higher cost,
  long-term debt, including the use of a portion of the proceeds from the issuance
  of Transition Bonds, which reduced interest charges by $34 million.
  
  
  
                                         15
  <PAGE>
  
  Other Income and Deductions
           Other income and deductions excluding interest charges was a loss of $5
  million for the quarter ended June 30, 1999 as compared to a loss of $27 million
  in the same 1998 period. The decrease of $22 million was primarily  attributable
  to a $10 million write-off of a non-regulated business venture in the prior year
  period and a $5 million  improvement in the performance of the Company's  equity
  investments in telecommunications.
  
  Income Taxes
           The  effective  tax rate was 32% for the quarter ended June 30, 1999 as
  compared to 38% in the same 1998 period.  The decrease in the effective tax rate
  was a result of tax benefits  associated  with the  implementation  of state tax
  planning  strategies,  partially offset by the  non-recognition for state income
  tax purposes of certain  operating  losses.  In addition,  the  disproportionate
  relationship  of regulated  plant tax  adjustments to income before income taxes
  and extraordinary item contributed to the decrease in the effective tax rate.
  
  Extraordinary Item
           During  the  second   quarter  of  1999,   the   Company   incurred  an
  extraordinary  charge of $26.7  million,  net of tax,  consisting  of prepayment
  premiums and the write-off of unamortized  deferred  financing costs  associated
  with the  early  retirement  of debt  with a portion  of the  proceeds  from the
  issuance of Transition Bonds.
  
  Preferred Stock Dividends
           Preferred  stock  dividends  for the  quarter  ended June 30, 1999 were
  consistent with the same 1998 period.
  
  
  Six Months Ended June 30, 1999 Compared to Six Months Ended June 30, 1998
  Operating Revenues
           Electric  revenues  increased $10 million for the six months ended June
  30,  1999  compared  to  the  same  1998  period.  The  increase  was  primarily
  attributable  to  higher  revenues  from the  generation  business  unit of $256
  million  partially offset by lower revenues from the distribution  business unit
  of $246 million. The increase from the generation business unit was attributable
  to $204 million from increased volume in Pennsylvania resulting from the sale of
  competitive  electric generation services by Exelon Energy,  increased wholesale
  revenues of $77 million from the  marketing of excess  generation  capacity as a
  result of retail  competition  and $14 million from the sale of generation  from
  Clinton  to IP,  partially  offset by $39  million of PJM  network  transmission
  service  revenue  in  the  comparable   1998  period.   The  decrease  from  the
  distribution business unit was attributable to $205 million as a result of lower
  volume  associated  with the  effects  of retail  competition  and $120  million
  related  to  the 8%  across-the-board  rate  reduction  mandated  by  the  Final
  Restructuring Order. These decreases were partially offset by $74 million of PJM
  network  transmission  service revenue and $5 million related to increased sales
  volume as a result of colder  weather  conditions  in the first  quarter of 1999
  partially  offset by milder weather  conditions in the second quarter of 1999 as
  compared to the prior year periods.
  
  
  
                                         16
  <PAGE>
  
           Gas revenues  increased  $36 million,  or 13%, for the six months ended
  June 30, 1999  compared to the same 1998  period.  The  increase  was  primarily
  attributable to $24 million from increased  volume as a result of cooler weather
  conditions  in the  beginning of the period as compared to the prior year period
  and $12 million from increased volume from new and existing customers.
  
  Fuel and Energy Interchange Expense
           Fuel and energy interchange expense increased $222 million, or 30%, for
  the six months  ended  June 30,  1999  compared  to the same 1998  period.  As a
  percentage of revenue, fuel and interchange expenses were 39% as compared to 31%
  in the comparable prior year period. These increases were attributable to higher
  fuel and energy interchange  expenses associated with the distribution  business
  unit of $119  million and the  generation  business  unit of $103  million.  The
  increase from the distribution  business unit was primarily  attributable to $51
  million of PJM network transmission service charges, $99 million of purchases in
  the spot  market and $21  million of  additional  gas  purchases  as a result of
  higher volume  associated with cooler weather early in the period and additional
  volume to new and existing  customers.  These increase were partially  offset by
  $55  million  of lower fuel costs as a result of lower  volume  associated  with
  Customer  Choice.  The increase from the generation  business unit was primarily
  attributable  to $200  million  related to increased  volume from Exelon  Energy
  sales,  partially offset by $45 million of lower fuel costs as a result of lower
  volume,  lower PJM network  transmission service charges of $39 million, and $19
  million of fuel savings  associated with the full return to service of the Salem
  Generating  Station  (Salem) in April 1998 which  decreased the need to purchase
  power to replace the output from these units.
  
  Operating and Maintenance Expense
           O&M expense increased $88 million, or 16% for the six months ended June
  30, 1999 compared to the same 1998 period. As a percentage of revenue, operating
  and  maintenance  expenses were 26% as compared to 22% in the  comparable  prior
  year period.  The generation  business unit's O&M expenses increased $50 million
  as a result of $25 million related to the revised Clinton management  agreement,
  $15 million  associated with the Salem  inventory  write-off and true-up of 1998
  reimbursement  of joint-owner  expenses and $10 million related to the growth of
  unregulated  retail  sales of  electricity,  partially  offset by $10 million of
  lower O&M  expenses  as a result of the full return to service of Salem in April
  1998. The distribution  unit's O&M expenses increased  approximately $22 million
  as a result of  additional  marketing  expenses  and  expenses  associated  with
  Customer  Choice.  In  addition,   the  Company  incurred  additional  costs  of
  approximately $11 million related to nuclear property  insurance and $16 million
  associated  with Year 2000  remediation  expenditures,  partially  offset by $10
  million of pension  credits as a result of the performance of the investments in
  the Company's pension plan.
  
  Depreciation and Amortization Expense
           Depreciation and amortization  expense decreased $202 million,  or 64%,
  for the six months ended June 30, 1999  compared to the same 1998  period.  As a
  percentage of revenue,  depreciation and amortization expense was 5% as compared
  to 13% in the comparable prior year period. The decrease was associated with the
  December  1997  restructuring  charge  through  which the  Company  wrote down a
  significant portion of its generating plant and regulatory assets.
  
  
  
                                         17
  <PAGE>
  
  Taxes Other Than Income
           Taxes other than income  decreased  $33  million,  or 22%,  for the six
  months ended June 30, 1999 compared to the same 1998 period.  As a percentage of
  revenue,  taxes other than income were 5%, as compared to 6%, in the  comparable
  prior year  period.  The decrease was  primarily  attributable  to a $30 million
  credit related to an adjustment to the Company's  Pennsylvania capital stock tax
  base as a result of the 1997  restructuring  charge and lower gross receipts tax
  of $6 million associated with lower retail electric and gas sales.
  
  Interest Charges
           Interest charges increased $15 million, or 8%, for the six months ended
  June 30, 1999  compared to the same 1998  period.  As a  percentage  of revenue,
  interest  charges were  comparable  to the prior year period at 8%. The increase
  was primarily  attributable to interest on the Transition  Bonds of $60 million,
  partially  offset by the Company's  ongoing  program to reduce and/or  refinance
  higher cost, long-term debt, including the use of a portion of the proceeds from
  the issuance of Transition Bonds, which reduced interest charges by $45 million.
  
  Other Income and Deductions
           Other income and deductions  excluding  interest  charges was a loss of
  $47 million for the six months  ended June 30, 1999 as compared to a loss of $40
  million  in the same 1998  period.  The  increase  of $7 million  was  primarily
  attributable  to a $15 million  write-off  of the  investment  in Grays Ferry in
  connection  with the  settlement  of  litigation,  and a charge  related  to the
  abandonment of an information  system of $7 million,  partially  offset by a $10
  million  write-off of a non-regulated  business venture in the prior year period
  and a $3  million  improvement  in  the  performance  of  the  Company's  equity
  investments in telecommunications ventures.
  
  Income Taxes
           The  effective  tax rate was 37% for the six months ended June 30, 1999
  as compared to 38% in the same 1998 period.  The decrease in the  effective  tax
  rate was a result of tax benefits  associated with the  implementation  of state
  tax  planning  strategies,  partially  offset by the  non-recognition  for state
  income  tax   purposes  of  certain   operating   losses.   In   addition,   the
  disproportionate  relationship  of  regulated  plant tax  adjustments  to income
  before income taxes and  extraordinary  item  contributed to the decrease in the
  effective tax rate.
  
  Extraordinary Item
           During  the  second   quarter  of  1999,   the   Company   incurred  an
  extraordinary  charge of $26.7  million,  net of tax,  consisting  of prepayment
  premiums and the write-off of unamortized  deferred  financing costs  associated
  with the  early  retirement  of debt  with a portion  of the  proceeds  from the
  issuance of Transition Bonds.
  
  Preferred Stock Dividends
       Preferred  stock  dividends  for the six months  ended  June 30,  1999 were
  consistent with the same 1998 period.
  
  
                                         18
  <PAGE>
  
  
  DISCUSSION OF LIQUIDITY AND CAPITAL RESOURCES
           Cash flows provided by operating  activities  decreased $258 million to
  $252  million for the six months ended June 30, 1999 as compared to $510 million
  in the same 1998 period.  The decrease was primarily  attributable  to less cash
  generated by  operations  of $192 million and changes in working  capital of $62
  million,  principally  related to accounts  receivable from  unregulated  energy
  sales.
  
           Cash flows used by investing  activities  were $279 million for the six
  months  ended June 30, 1999 as compared to $265 million in the  comparable  1998
  period and consisted primarily of capital expenditures for plant.
  
           Cash flows provided by financing  activities  were $879 million for the
  six months ended June 30, 1999, as compared to cash used in financing activities
  of  $173  million  in  the  comparable  prior  year  period.  The  increase  was
  attributable to the issuance of $4 billion of Transition Bonds by PETT partially
  offset by the  repayment of  short-term  and  long-term  debt  aggregating  $1.5
  billion and the  application of $1.5 billion of Transition  Bond proceeds to the
  repurchase of common stock,  including  the  settlement of the Company's  common
  stock forward purchase contract.
  
           On March 25, 1999,  PETT issued $4 billion of its  Transition  Bonds to
  securitize a portion of the Company's  authorized  stranded cost  recovery.  The
  Transition  Bonds are solely  obligations  of PETT,  secured  by the  Intangible
  Transition  Property  (ITP) sold by the  Company to PETT.  Upon  issuance of the
  Transition  Bonds,  a  portion  of  the  competitive  transition  charges  to be
  collected by the Company to recover  stranded costs was designated as Intangible
  Transition Charges (ITC). The ITC is an irrevocable  non-bypassable  usage based
  charge that is  calculated  to allow for the  recovery of debt service and costs
  related to the issuance of the Transition  Bonds. The ITC will be allocated from
  CTC and variable distribution charges (both of which are usage based charges).
  
           PETT used the $3.95  billion of  proceeds  of the  Transition  Bonds to
  purchase the ITP from the  Company.  Although  the  Transition  Bonds are solely
  obligations of PETT, they are included in the consolidated long-term debt of the
  Company.  In accordance  with the terms of the  Competition  Act, the Company is
  utilizing the proceeds  principally to reduce stranded costs and capitalization.
  The  Company  currently  plans to reduce  its  capitalization  in the  following
  proportions: fixed and floating-rate debt, 50%; preferred securities, 7%; common
  equity,  43%.  Through June 30, 1999,  the Company  utilized the net proceeds to
  repurchase  38.7 million shares of Common Stock for an aggregate  purchase price
  of $1.507  billion;  to retire:  $811 million of First  Mortgage  Bonds,  a $400
  million term loan,  $208 million of commercial  paper,  $150 million of accounts
  receivable financing and a $139 million capital lease obligation;  to repurchase
  $9 million of Company Obligated Mandatorily Redeemable Preferred Securities of a
  Partnership  (COMRPS);  and to pay $25  million  of  debt  issuance  costs.  The
  remaining  proceeds of  approximately  $750 million are included in cash at June
  30, 1999. In addition,  on July 30, 1999,  the Company  redeemed $212 million of
  COMRPS.  On August 2, 1999,  the  Company  retired  $37  million of  Mandatorily
  Redeemable  Preferred  Stock pursuant to the sinking fund  requirements of those
  securities.  The  Company  currently  anticipates  that  it  will  complete  the
  repurchase of common equity  through open market  purchases from time to time in
  compliance with Securities and Exchange  Commission  rules. The number of shares
  purchased  and the timing and manner or  purchases  are  dependent  upon  market
  conditions.
  
                                         19
  <PAGE>
  
           Although the Company has sold the ITP to PETT, the ITC revenue, as well
  as all interest expense and amortization  expense associated with the Transition
  Bonds,  is  reflected on the  Company's  Consolidated  Statement of Income.  The
  combined  schedule for  amortization  of the CTC and ITC assets is in accordance
  with the amortization  schedule set forth in the Final Restructuring Order. As a
  result  of the  issuance  of the  Transition  Bonds  and  the  on-going  capital
  reduction by the Company, the Company expects its debt-to-total capital ratio to
  be 60%, exclusive of the Transition Bonds, upon completion of the application of
  the proceeds  from  securitization.  The Company  completed  the majority of the
  targeted debt and preferred  security  reductions by August 2, 1999, and expects
  that the  remaining  reductions  will be completed  by December  31,  1999.  The
  weighted  average  cost  of debt  and  preferred  securities  to be  retired  is
  approximately   6.8%.  The  additional  interest  expense  associated  with  the
  Transition Bonds, which have an effective  interest rate of approximately  5.8%,
  will be partially offset by the anticipated interest savings associated with the
  debt and  preferred  securities  that will be  retired.  The  Company  currently
  estimates  that  the  impact  of this  additional  expense,  combined  with  the
  anticipated  reduction  in common  equity,  will  result in  earnings  per share
  benefits of approximately  $.15 and $.50 in 1999 and 2000,  respectively.  These
  estimated  earnings  per share could change and are largely  dependent  upon the
  timing  and  price of  common  stock  repurchases  and  anticipated  net  income
  available to common stock.
  
           At June 30,  1999,  the Company had  outstanding  $226 million of notes
  payable, all of which were commercial paper. In addition,  at June 30, 1999, the
  Company had formal and informal lines of bank credit  aggregating  $100 million.
  At June 30, 1999, the Company had no short-term investments.
  
           On May 3, 1999, Standard & Poor's upgraded its ratings on the Company's
  overall corporate credit to "A-" from "BBB+", first and refunding mortgage bonds
  and  collateralized  medium-term  notes to "A"  from  "BBB+",  hybrid  preferred
  securities, capital trust securities and preferred stock to "BBB" from "BBB-".
  
  
  YEAR 2000 READINESS DISCLOSURE
           The Year 2000 Project (Y2K Project) is addressing  the issue  resulting
  from  computer  programs  using  two  digits  rather  than  four to  define  the
  applicable   year  and  other   programming   techniques   that  constrain  date
  calculations or assign special  meanings to certain dates.  Any of the Company's
  computer  systems  that have  date-sensitive  software  or  microprocessors  may
  recognize  a date using "00" as the year 1900  rather  than the year 2000.  This
  could  result in a system  failure or  miscalculations  causing  disruptions  of
  operations,  including,  a temporary  inability  to process  transactions,  send
  bills,  operate  generating  stations,  or engage  in  similar  normal  business
  activities.  Due to the severity of the potential  impact of the Year 2000 Issue
  (Y2K  Issue)  on  the  electric   utility   industry,   the  Company  adopted  a
  comprehensive  schedule to achieve Y2K  readiness  by the time  specified by the
  Nuclear  Regulatory  Commission  (NRC).  The  Company  has  dedicated  extensive
  resources to the Project and believes it is progressing on schedule.
  
                                         20
  <PAGE>
  
           The  Company  determined  that it was  required  to modify,  convert or
  replace significant portions of its software and a subset of its system hardware
  and embedded technology so that its computer systems will properly utilize dates
  beyond  December  31,  1999.  The  Company  presently  believes  that with these
  modifications,  conversions and  replacements the effect of the Y2K Issue on the
  Company can be mitigated.  If such  modifications,  conversions and replacements
  are not made, or are not completed in a timely manner,  the Y2K Issue could have
  a material impact on the operations and financial condition of the Company.  The
  costs associated with this potential impact are not presently quantifiable.  The
  Company is  utilizing  both  internal and external  resources to  reprogram,  or
  replace and test software and computer systems for the Project.  The Project was
  scheduled  for  completion  by July  1,  1999,  except  for a  small  number  of
  modifications,  conversions  or  replacements  that are impacted by PUC changes,
  vendor dates and/or are being  incorporated into scheduled plant outages between
  July and November 1999. The scheduled Project  completion date was met, with the
  limited anticipated exceptions noted above.
  
           The  Project  is  divided  into  four  major   sections  -  Information
  Technology Systems (IT Systems),  Embedded  Technology (devices used to control,
  monitor or assist the operation of equipment,  machinery or plant), Supply Chain
  (third-party  suppliers and customers),  and Contingency  Planning.  The general
  phases common to the first two sections  are: (1)  inventorying  Y2K items;  (2)
  assigning  priorities  to identified  items;  (3) assessing the Y2K readiness of
  items  determined to be material to the Company;  (4) converting  material items
  that are determined not to be Y2K ready;  (5) testing  material  items;  and (6)
  designing and implementing  contingency plans for each critical Company process.
  Material  items are those  believed by the Company to have a risk  involving the
  safety of  individuals,  may cause  damage to  property or the  environment,  or
  affect revenues.
  
           The IT Systems  section  includes both the  conversion of  applications
  software that is not Y2K ready and the  replacement  of software when  available
  from the supplier.  The Project has identified 363 critical systems of which 234
  are IT Systems and 129  Embedded  Systems.  The current  readiness  status of IT
  Systems is set forth below:
  
  Number of Systems Progress Status
  
  233 Systems                Y2K Ready
   1  System                 In Testing
  
  Contingency planning for IT Systems has been completed.
  
           The  remaining  129  systems are the  Embedded  Systems  consisting  of
  hardware  and  systems  software  other than IT Systems.  The current  readiness
  status of those systems is set forth below:
  
  Number of Systems Progress Status
  
  120 Systems                Y2K Ready
   9  Systems                In Progress
  
  Contingency planning for Embedded Technology has been completed.
  
                                         21
  <PAGE>
  
           The Supply  Chain  section  includes  the  process of  identifying  and
  prioritizing  critical  suppliers and communicating  with them about their plans
  and progress in addressing  the Y2K Issue.  The process of  evaluating  critical
  suppliers was completed on March 31, 1999. The Company has completed contingency
  plans for all critical suppliers.
  
           In addition to addressing  contingency  plans with key  suppliers,  the
  Company is currently  developing  contingency plans to address how to respond to
  internal  events which may disrupt  normal  operations.  These plans address Y2K
  risk  scenarios  that cross  departments  and business  units.  Emergency  plans
  already exist that cover various aspects of the Company's business.  These plans
  are being  reviewed  and updated to address  the Y2K Issue.  The Company is also
  participating in industry contingency planning efforts.
  
           The estimated total cost of the Project is $75 million, the majority of
  which is attributable to testing.  This estimate includes the Company's share of
  Y2K costs for jointly owned facilities. The total amount expended on the Project
  through June 30, 1999 was $44 million.  The Company  expects to fund the Project
  from  operating  cash  flows.  The  Company's  failure to become Y2K ready could
  result in an interruption in or a failure of certain normal business  activities
  or operations.  In addition, there can be no assurance that the systems of other
  companies on which the  Company's  systems  rely or with which they  communicate
  will be  converted in a timely  manner,  or that a failure to convert by another
  company,  or a conversion that is incompatible with the Company's systems,  will
  not  have  a  material  adverse  effect  on the  Company.  Such  failures  could
  materially and adversely affect the Company's  results of operations,  liquidity
  and financial condition.  The Company is currently developing  contingency plans
  to  address  how to  respond  to  events  that may  disrupt  normal  operations,
  including  activities  with PJM.  The costs of the Project and the date on which
  the Company plans to complete the Y2K modifications are based on estimates, that
  were derived  utilizing  numerous  assumptions of future  events,  including the
  continued availability of certain resources,  third-party modification plans and
  other factors,  such as regulatory  requirements that impact key systems.  There
  can be no assurance that these estimates will be achieved.  Actual results could
  differ  materially  from the  projections.  Specific  factors that might cause a
  material change include,  but are not limited to, the  availability  and cost of
  trained  personnel,  the  ability to locate and correct  all  relevant  computer
  programs and microprocessors.
  
           The Project is expected to significantly  reduce the Company's level of
  uncertainty about the Y2K Issue. The Company believes that the completion of the
  Project, as scheduled, minimizes the possibility of significant interruptions of
  normal operations.
  
           On July 17, 1998, an order was entered by the PUC  instituting a formal
  investigation  by the Office of  Administrative  Law on Year 2000  compliance by
  jurisdictional  fixed utilities and  mission-critical  service providers such as
  the PJM (the  Investigation).  The order requires,  (1) a written  response to a
  list  of  compliance   program   questions  by  August  6,  1998  and,  (2)  all
  jurisdictional fixed utilities be Year 2000 compliant by March 31, 1999 or, if a
  utility determines that  mission-critical  systems cannot be Year 2000 compliant
  on or before  March  31,  1999,  the  utility  is  required  to file a  detailed
  contingency plan. The PUC adopted the federal  government's  definition for Year
  2000  compliance and further  defined Year 2000  compliance as a  jurisdictional
  
  
                                         22
  <PAGE>
  
  utility  having all  mission-critical  Year 2000  hardware and software  updates
  and/or replacements  installed and tested on or before March 31, 1999. On August
  6, 1998,  the Company filed its written  response,  in which the Company  stated
  that with a few carefully-assessed and closely-managed  exceptions,  the Company
  will have all mission-critical systems Year 2000 ready by June 1999. Pursuant to
  the  formal  investigation  on  Year  2000  compliance,  the  Company  presented
  testimony before the PUC on November 20, 1998.
  
           On February 19, 1999, the PUC issued a Secretarial Letter notifying the
  Company that it had hired a consultant  to perform an  assessment of the Company
  and thirteen other  utilities to evaluate the accuracy of their responses to the
  compliance  program questions and testimony provided before the PUC. The Company
  complied  with the PUC's  directive  in the  Secretarial  Letter to file updated
  written responses to compliance questions by March 8, 1999, and to meet with the
  consultant  during a one-day  on-site  review session on March 8, 1999. On March
  31,  1999,   the  Company  filed   contingency   plans  with  the  PUC  for  its
  mission-critical  systems  scheduled  to be  ready  after  the  March  31,  1999
  deadline.
  
           On April 8,  1999,  the PUC  issued an order  requiring  the  Office of
  Administrative  Law Judge to identify (i) utilities which have complied with the
  PUC's order of July 17, 1998 (the Order); (ii) utilities which have demonstrated
  good cause for an extension of time within which they will fully comply with the
  Order; and (iii) those utilities which have not complied with the Order and have
  not shown good cause for an extension. The PUC required that this information be
  posted to the PUC internet  website and  periodically  updated.  The PUC further
  ordered that the  Investigation  with respect to utilities who have demonstrated
  good cause for an  extension of time remain open and under the  jurisdiction  of
  the  Office  of  Administrative  Law  Judge  until  compliance  is  achieved  or
  enforcement  is  warranted.  PECO  Energy  has been  identified  by the PUC as a
  utility which has demonstrated  good cause for an extension of time within which
  it  will  fully  comply  with  the  Order.  Additional  reporting  dates  to the
  Administrative Law Judge include July 1, 1999 and October 1, 1999.
  
           On May 11, 1998, the NRC issued a generic letter  requiring all nuclear
  plant operators to provide the NRC with the following information concerning the
  operators' programs,  planned or implemented,  to address Year 2000 computer and
  system issues at its facilities:  (1) submission of a written response within 90
  days,  indicating  whether the  operator  has pursued  and  continues  to pursue
  implementation  of Year  2000  programs  and  addressing  the  program's  scope,
  assessment process,  plans for corrective  actions,  quality assurance measures,
  contingency  plans and  regulatory  compliance,  and (2) submission of a written
  response,  no later than July 1, 1999,  confirming that such facilities are Year
  2000  ready,  or will be Year  2000  ready,  by the year  2000  with  regard  to
  compliance with the terms and conditions of the license(s) and NRC  regulations.
  On July 30,  1998,  the  Company  filed its  90-day  required  written  response
  indicating  that the Company has pursued and is continuing to pursue a Year 2000
  program  which  is  similar  to that  outlined  in  Nuclear  Utility  Year  2000
  Readiness, NEI/NUSMG 97.07.
  
           From November 3 to November 5, 1998, members of the NRC staff conducted
  an audit of the Company's Year 2000 Program for the Limerick Generating Station,
  Units No. 1 and No. 2. Some of the  observations  of the audit team  included in
  their written  report  issued on December 18, 1998,  were that (1) the Company's
  readiness  program  is  comprehensive  and based on the  guidance  contained  in
  
  
                                         23
  <PAGE>
  
  NEI/NUSMG  97.07,  (2) the program is receiving  proper  management  support and
  oversight, and (3) project schedules are being aggressively pursued.
  
           On April 28, 1999,  the NRC issued  Information  Notice 99-12  advising
  nuclear power plant licensees that NRC staff would be conducting additional Year
  2000 readiness and contingency planning  site-specific reviews at all commercial
  nuclear power plants. The NRC performed its site-specific review of Peach Bottom
  from May 24 to May 28, 1999,  and its review of Limerick from June 7 to June 10,
  1999.
  
           On June 30, 1999,  PECO Energy filed its completed  response to Generic
  Letter 98-01. In the response,  PECO Energy confirmed that with the exception of
  five  non-safety  plant  systems,  its Peach  Bottom  Atomic  Power  Station and
  Limerick  Generating  Stations are Year 2000 ready.  The Company advised the NRC
  that remediation for three of the remaining  systems is scheduled for completion
  by September 30, 1999, and remediation for the other two systems is scheduled to
  occur during planned plant outages in September 1999.
  
           For additional information regarding the Year 2000 Readiness Disclosure
  see "Management's  Discussion and Analysis of Financial Condition and Results of
  Operations" in the Company's Annual Report to Shareholders for the year 1998.
  
  
  FORWARD-LOOKING STATEMENTS
           Except for the historical  information contained herein, certain of the
  matters discussed in this Report are forward-looking  statements,  including the
  estimated  earnings per share benefits of the application of the Transition Bond
  proceeds  for  1999  and  2000,  and  accordingly,  are  subject  to  risks  and
  uncertainties.  The factors that could cause actual results to differ materially
  include  those  discussed  herein as well as those listed in notes 2, 8 and 9 of
  Notes to Condensed Consolidated Financial Statements and other factors discussed
  in the Company's  filings with the SEC. Readers are cautioned not to place undue
  reliance on these forward-looking statements, which speak only as of the date of
  this  Report.  The Company  undertakes  no  obligation  to publicly  release any
  revision to these forward-looking  statements to reflect events or circumstances
  after the date of this Report.
  
  
  ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
  
           The Company has entered  into  interest  rate swaps to manage  interest
  rate  exposure  associated  with the  issuance  of two  floating  rate series of
  Transition  Bonds. At June 30, 1999, the fair value of these instruments was $52
  million based on the present value difference between the contracted rate (i.e.,
  hedged rate) and the market rates at that date.  A  hypothetical  50 basis point
  increase or  decrease in the spot yield at June 30, 1999 would have  resulted in
  an aggregate  fair value of these  interest rate swaps of $91.2 million or $10.7
  million, respectively. If the derivative instruments had been terminated at June
  30, 1999,  these  estimated  fair values  represent the amount to be paid by the
  counterparties to the Company.
  
                                         24
  <PAGE>
  
           The Company's growing market share in the retail and wholesale electric
  marketplace  increases the Company's reliance on the efficient  operation of its
  generating  units.  The  Company's  ability  to  fully  capitalize  on  volatile
  wholesale  market prices is also  dependent on the  performance of the Company's
  generating units.
  
  
  
  
  
                                         25
  <PAGE>
  PART II - OTHER INFORMATION
  
  
  ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
  
           Information  regarding the  submission of matters to a vote of security
  holders is presented in the March 31, 1999 Form 10-Q.
  
  ITEM 5.  OTHER INFORMATION
  
           As  previously  reported  in the  1998  Form  10-K,  the NRC  issued  a
  confirmatory  order  modifying  the  license  for  Limerick  Generating  Station
  (Limerick)  Units No. 1 and No. 2  requiring  that the  Company  complete  final
  implementation  of corrective  actions on the Thermo-Lag 330 issue by completion
  of the April 1999  refueling  outage of Limerick Unit No. 2. By letter dated May
  3, 1999,  the NRC approved the  Company's  request to extend the  completion  of
  Thermo-lag corrective actions at Limerick until September 30, 1999.
  
           As previously  reported in the 1998 Form 10-K, in October 1990, General
  Electric  Company (GE) reported that crack  indications were discovered near the
  seam welds of the core  shroud  assembly  in a GE Boiling  Water  Reactor  (BWR)
  located outside the United States.  As a result,  GE issued a letter  requesting
  that the owners of GE BWRs take interim corrective  actions,  including a review
  of fabrication  records and visual  examinations of accessible areas of the core
  shroud seam welds.  Each of the  reactors at Limerick  and Peach  Bottom is a GE
  BWR. In accordance with industry experience and guidance, initial examination of
  Limerick  Unit No. 2 was  completed  during  the April  1999  refueling  outage.
  Although crack  indications were identified,  the results of the inspections and
  evaluations  conclude that the condition of the Limerick Unit No. 2 core shroud,
  projected  through at least the next operating cycle,  will support the required
  safety  margins,   specified  in  the  ASME  code  and  reinforced  by  industry
  recommendations.
  
          As  previously  reported  in the 1998 Form 10-K,  as a result of several
  BWRs  experiencing  clogging  of some  emergency  core  cooling  system  suction
  strainers,  which are part of the water supply system for  emergency  cooling of
  the reactor  core,  the NRC issued a Bulletin in May 1996 to  operators  of BWRs
  requesting  that measures be taken to minimize the  potential for clogging.  The
  NRC proposed  three  resolution  options,  including the  installation  of large
  capacity passive strainers,  with a request that actions be completed by the end
  of the  unit's  first  refueling  outage  after  January  1997.  Strainers  were
  installed at Peach Bottom Unit No. 3 during the October 1997  refueling  outage.
  Strainers  were  installed at Peach  Bottom Unit No. 2 and  Limerick  Unit No. 1
  during their  refueling  outages in October  1998 and April 1998,  respectively.
  Strainers  were installed at Limerick Unit No. 2 during the April 1999 refueling
  outage. The Company cannot predict what other actions,  if any, the NRC may take
  in this matter.
  
            On June 22, 1999,  Pennsylvania Governor Tom Ridge signed into law the
  Natural Gas Choice and  Competition  Act  ("Act")  which  expands  choice of gas
  suppliers to residential and small commercial  customers and eliminates the five
  percent gross receipts tax on gas  distribution  companies'  sales of gas. Large
  commercial  and industrial  customers  have been able to choose their  suppliers
  since 1984.  Currently,  approximately  one-third of the Company's  total yearly
  throughput is supplied by third parties.
  
  
  
                                         26
  <PAGE>
  
           The  Act  permits  gas  distribution  companies  to  continue  to  make
  regulated  sales of gas to their  customers.  The Act  does not  deregulate  the
  transportation  service  provided by gas  distribution  companies  which remains
  subject to rate regulation.  Gas distribution companies will continue to provide
  billing, metering, installation, maintenance and emergency response services.
  
           In  compliance  with  the  schedule   ordered  by  the  Public  Utility
  Commission  ("PUC"),  the  Company  must file with the PUC by December 2, 1999 a
  restructuring  plan for the  implementation  of gas  deregulation  and  customer
  choice of gas service suppliers in its service territory  (Restructuring  Plan).
  The  Company  expects gas to flow on its system  pursuant to customer  choice on
  July 1, 2000.  The Company is currently  analyzing  the impact of the Act on its
  operations. The Company believes the impact on the Company would not be material
  because of the PUC's existing requirement that gas distribution companies cannot
  collect  more  than  the  actual  cost of gas  from  customers,  and  the  Act's
  requirement that suppliers must accept assignment or release, at contract rates,
  the portion of the gas distribution company's firm interstate pipeline contracts
  required to serve the suppliers' customers.
  
  
  ITEM 6.  EXHIBITS AND REPORTS ON FORM 8-K
  (a)      Exhibits:
  
           27 - Financial Data Schedule.
  
  (b)      Reports on Form 8-K filed during the reporting period:
  
           Report,  dated  April 15,  1999  reporting  information  under "ITEM 5.
                    OTHER EVENTS" regarding AmerGen Energy Company, LLC, the joint
                    venture between the Company and British Energy,  Inc., signing
                    an interim  agreement  to purchase the Clinton  Nuclear  Power
                    Station from  Illinois  Power (IP),  a subsidiary  of Illinova
                    Corporation.
  
           Report,  dated June 24, 1999 reporting information under "ITEM 5. OTHER
                    EVENTS" regarding AmerGen's signing a definitive  agreement to
                    purchase  the  Nine  Mile  Point  Unit  1  Nuclear  Generating
                    Facility  from Niagara  Mohawk  Power  Corporation  (NIMO),  a
                    subsidiary of Niagara Mohawk  Holdings,  Inc. AmerGen has also
                    entered  into an agreement  to purchase  NIMO's 41%  ownership
                    interest in Nine Mile Point Unit 2 Nuclear Generating Facility
                    (NMP-2) and New York State  Electric  and Gas Corp.'s  (NYSEG)
                    18% interest in NMP-2.  NYSEG is a wholly owned  subsidiary of
                    Energy East, Inc.
  
           Reports on Form 8-K filed subsequent to the reporting period:
  
           Report,  dated July 1, 1999 reporting  information under "ITEM 5. OTHER
                    EVENTS"   regarding   AmerGen's  signing  a  definitive  asset
                    purchase agreement to purchase Clinton.
  
  
  
                                         27
  <PAGE>
  
                                     Signatures
  
           Pursuant to  requirements  of the Securities  Exchange Act of 1934, the
  registrant  has duly  caused  this  report  to be  signed  on its  behalf by the
  undersigned thereunto duly authorized.
  
  
  
  
                                 PECO ENERGY COMPANY
  
                                 /s/ Michael J. Egan
                                 MICHAEL J. EGAN
                                 Vice President and
                                 Senior Vice President and
                                 Chief Financial Officer
                                 (Chief Accounting Officer)
  
  Date:  August 13, 1999
  
                                         28
metadata_documents: [{"type": "10-Q", "sequence": "1", "secsgml_size_bytes": 97183}]
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": "99689428"}, "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 June 30, 1999
  
                                         OR
  
            [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
                           SECURITIES EXCHANGE ACT OF 1934
  
                           Commission file number: 1-1401
  
                                 PECO Energy Company
               (Exact name of registrant as specified in its charter)
  
                   Pennsylvania                       23-0970240
            (State or other jurisdiction of         (I.R.S. Employer
            incorporation or organization)          Identification No.)
  
            2301 Market Street, Philadelphia, PA          19103
          (Address of principal executive offices)      (Zip Code)
  
                                   (215) 841-4000
                (Registrant's telephone number, including area code)
  
           Indicate by check mark whether the registrant (1) has filed all reports
           required to be filed by Section 13 or 15(d) of the Securities  Exchange
           Act of 1934 during the preceding 12 months (or for such shorter  period
           that the  registrant  was required to file such  reports),  and (2) has
           been subject to such filing requirements for the past 90 days.
  
                                  Yes    X            No  ___
  
           Indicate  the  number of  shares  outstanding  of each of the  issuer's
           classes of common stock as of the latest practicable date:
  
           The Company  had  186,603,406  shares of common  stock  outstanding  on
           August 6, 1999.
  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 June 30,         Six Months Ended June 30,
                                                             1999              1998             1999             1998
                                                          -----------      -----------     ------------     ------------
  OPERATING REVENUES
  Electric                                           $   1,105.4          1,131.8          2,144.3          2,134.8
       Gas                                                       89.0             83.4            306.5            270.6
                                                          -----------      -----------     ------------     ------------
  TOTAL OPERATING REVENUES                                    1,194.4          1,215.2          2,450.8          2,405.4
                                                          -----------      -----------     ------------     ------------
  OPERATING EXPENSES
       Fuel and Energy Interchange                              500.3            360.2            965.4            743.2
       Operating and Maintenance                                338.9            256.0            627.6            539.2
       Depreciation and Amortization                             57.6            160.9            113.9            315.6
       Taxes Other Than Income                                   45.2             71.8            120.5            153.9
                                                          -----------      -----------     ------------     ------------
                                                                942.0            848.9          1,827.4          1,751.9
                                                          -----------      -----------     ------------     ------------
  OPERATING INCOME                                              252.4            366.3            623.4            653.5
                                                          -----------      -----------     ------------     ------------
  
  OTHER INCOME AND DEDUCTIONS
       Interest Expense                                        (113.5)           (86.0)          (187.8)          (171.0)
       Company Obligated Mandatorily Redeemable
            Preferred Securities of a Partnership                (7.4)            (8.2)           (14.8)           (15.9)
       Allowance for Funds Used During Construction               1.7              0.7              2.1              1.3
       Other, Net                                                (4.6)           (26.9)           (46.6)           (39.7)
                                                          -----------      -----------     ------------     ------------
  
  TOTAL OTHER INCOME AND DEDUCTIONS                            (123.8)          (120.4)          (247.1)          (225.3)
                                                          -----------      -----------     ------------     ------------
  
  INCOME BEFORE INCOME TAXES AND
     EXTRAORDINARY ITEM                                         128.6            245.9            376.3            428.2
  
  INCOME TAXES                                                   41.0             94.4            139.0            163.1
                                                          -----------      -----------     ------------     ------------
  
  INCOME BEFORE EXTRAORDINARY ITEM                               87.6            151.5            237.3            265.1
  
  EXTRAORDINARY ITEM - NET OF INCOME TAXES                      (26.7)            --              (26.7)            --
                                                          -----------      -----------     ------------     ------------
  
  NET INCOME                                                     60.9            151.5            210.6            265.1
  
  PREFERRED STOCK DIVIDENDS                                       3.3              3.3              6.6              6.6
                                                          -----------      -----------     ------------     ------------
  
  EARNINGS APPLICABLE TO COMMON STOCK                     $      57.6      $     148.2      $     204.0      $     258.5
                                                          ===========      ===========     ============     ============
  
  AVERAGE SHARES OF COMMON STOCK
       OUTSTANDING (Millions)                                   192.0            222.7            207.6            222.6
                                                          ===========      ===========     ============     ============
  
  BASIC AND DILUTIVE EARNINGS PER
  AVERAGE COMMON SHARES BEFORE EXTRAORDINARY ITEM         $      0.44      $      0.66     $       1.11     $       1.16
  EXTRAORDINARY ITEM                                            (0.14)            --              (0.13)            --
                                                          -----------      -----------     ------------     ------------
  BASIC EARNINGS PER AVERAGE COMMON SHARE                 $      0.30      $      0.66     $       0.98     $       1.16
                                                          ===========      ===========     ============     ============
  
  DIVIDENDS PER AVERAGE COMMON SHARE                      $      0.25      $      0.25     $       0.50     $       0.50
                                                          ===========      ===========     ============     ============
  See Notes to Condensed Consolidated Financial Statements.
  
                                         2
  PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
                        CONDENSED CONSOLIDATED BALANCE SHEETS
                                (Millions of Dollars)
  June 30,           December 31,
                                                                                 1999                1998
                                                                              ----------          ----------
                                                                             (Unaudited)
  ASSETS
  
  UTILITY PLANT
  Electric - Transmission & Distribution                                     $   3,890.8         $   3,833.8
  Electric - Generation                                                          1,732.3             1,713.4
  Gas                                                                            1,141.2             1,132.0
  Common                                                                           409.3               407.3
                                                                              ----------          ----------
  
                                                                                 7,173.6             7,086.5
  Less Accumulated Provision for Depreciation                                    3,007.6             2,891.3
                                                                              ----------          ----------
  
                                                                                 4,166.0             4,195.2
  Nuclear Fuel, net                                                                296.7               141.9
  Construction Work in Progress                                                    375.0               272.6
  Leased Property, net                                                               0.5               154.3
                                                                              ----------          ----------
  
                                                                                 4,838.2             4,764.0
                                                                              ----------          ----------
  
  CURRENT ASSETS
  Cash and Temporary Cash Investments                                              899.6                48.1
  Accounts Receivable, net
       Customer                                                                    213.1                97.5
       Other                                                                       376.2               213.2
  Inventories, at average cost
       Fossil Fuel                                                                  62.9                92.3
       Materials and Supplies                                                      108.8                82.1
  Deferred Income Taxes                                                              7.7               (14.1)
  Other                                                                            109.0                19.0
                                                                              ----------          ----------
  
                                                                                 1,777.3               538.1
                                                                              ----------          ----------
  
  DEFERRED DEBITS AND OTHER ASSETS
  Competitive Transition Charge                                                  5,274.6             5,274.6
  Recoverable Deferred Income Taxes                                                609.2               614.4
  Deferred Non-Pension Postretirement Benefits Costs                                87.7                90.9
  Investments                                                                      554.8               538.1
  Loss on Reacquired Debt                                                           73.9                77.2
  Other                                                                            131.0               107.1
                                                                              ----------          ----------
  
                                                                                 6,731.2             6,702.3
                                                                              ----------          ----------
  
  TOTAL                                                                       $ 13,346.7          $ 12,004.4
                                                                              ==========          ==========
  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)
  June 30,          December 31,
                                                                                1999                1998
                                                                              ----------          ----------
                                                                             (Unaudited)
  CAPITALIZATION AND LIABILITIES
  
  CAPITALIZATION
  Common Shareholders' Equity
  Common Stock (No Par)                                                $    3,616.7        $    3,589.0
       Other Paid-In Capital                                                         1.2                 1.2
       Accumulated Deficit                                                        (422.5)             (532.9)
       Treasury Stock                                                           (1,507.3)                 --
  Preferred and Preference Stock
       Without Mandatory Redemption                                                137.5               137.5
       With Mandatory Redemption                                                    92.7                92.7
  Company Obligated Mandatorily Redeemable
       Preferred Securities of a Partnership                                       340.4               349.4
  Long-Term Debt                                                                 6,092.2             2,919.6
                                                                              ----------          ----------
  
                                                                                 8,350.9             6,556.5
                                                                              ----------          ----------
  
  CURRENT LIABILITIES
  Notes Payable, Bank                                                              226.0               525.0
  Long-Term Debt Due Within One Year                                               146.1               361.5
  Capital Lease Obligations Due Within One Year                                     --                  69.0
  Accounts Payable                                                                 357.5               316.2
  Taxes Accrued                                                                    187.4               170.5
  Interest Accrued                                                                 104.9                61.5
  Deferred Energy Costs - Gas                                                       26.3               (29.9)
  Other                                                                            235.6               217.4
                                                                              ----------          ----------
  
                                                                                 1,283.8             1,691.2
                                                                              ----------          ----------
  
  DEFERRED CREDITS AND OTHER LIABILITIES
  Capital Lease Obligations                                                          0.5                85.3
  Deferred Income Taxes                                                          2,355.3             2,376.9
  Unamortized Investment Tax Credits                                               292.8               300.0
  Pension Obligation                                                               219.3               219.3
  Non-Pension Postretirement Benefits Obligation                                   436.1               421.1
  Other                                                                            408.0               354.1
                                                                              ----------          ----------
  
                                                                                 3,712.0             3,756.7
                                                                              ----------          ----------
  
  COMMITMENTS AND CONTINGENCIES (NOTE 8)
  
  TOTAL                                                                      $  13,346.7          $ 12,004.4
                                                                             ===========          ==========
  See Notes to Condensed Consolidated Financial Statements.
  
                                         4
  PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
                   CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
                                     (Unaudited)
                                (Millions of Dollars)
  Six Months Ended June 30,
                                                                         1999             1998
                                                                     ----------         --------
  CASH FLOWS FROM OPERATING ACTIVITIES
  NET INCOME                                                         $    210.6         $  265.1
  EXTRAORDINARY ITEM, NET OF INCOME TAXES                                  26.7             --
                                                                     ----------         --------
  
  INCOME BEFORE EXTRAORDINARY ITEM                                        237.3            265.1
  
  Adjustments to Reconcile Net Income to Net Cash
       Provided by Operating Activities:
  Depreciation and Amortization                                           149.4            343.0
  Deferred Income Taxes                                                   (38.2)           (29.3)
  Amortization of Investment Tax Credits                                   (7.2)            (9.0)
  Deferred Energy Costs                                                    56.1             27.1
  Changes in Working Capital:
       Accounts Receivable                                               (278.5)           (87.1)
       Inventories                                                          2.7              9.0
       Accounts Payable                                                    41.3            (11.3)
       Other Current Assets and Liabilities                                14.4            (68.8)
  Other Items Affecting Operations                                         74.4             71.3
                                                                     ----------         --------
  
  CASH FLOWS PROVIDED BY OPERATING ACTIVITIES                             251.7            510.0
                                                                     ----------         --------
  
  CASH FLOWS FROM INVESTING ACTIVITIES
  
  Investment in Plant                                                    (244.4)          (229.1)
  Increase in Investments                                                 (35.0)           (35.8)
                                                                     ----------         --------
  
  NET CASH FLOWS USED IN INVESTING ACTIVITIES                            (279.4)          (264.9)
                                                                     ----------         --------
  
  CASH FLOWS FROM FINANCING ACTIVITIES
  
  Issuance of Long-Term Debt                                            4,000.0              6.4
  Common Stock Repurchase                                              (1,507.3)            --
  Debt Repayments                                                      (1,202.5)           (96.8)
  Change in Short-Term Debt                                              (299.0)           (55.5)
  Dividends on Preferred and Common Stock                                (109.9)          (117.8)
  Issuance of Company Obligated Mandatorily
       Redeemable Preferred Securities of a Partnership                    --               78.1
  Issuance of Common Stock                                                 14.0              9.3
  Other Items Affecting Financing                                         (16.1)             3.1
                                                                     ----------         --------
  
  NET CASH FLOWS PROVIDED BY (USED IN) FINANCING ACTIVITIES               879.2           (173.2)
                                                                     ----------         --------
  
  INCREASE IN CASH AND CASH EQUIVALENTS                                   851.5             71.9
                                                                     ----------         --------
  
  CASH AND CASH EQUIVALENTS AT BEGINNING OF  PERIOD                        48.1             33.4
                                                                     ----------         --------
  
  CASH AND CASH EQUIVALENTS AT END OF  PERIOD                        $    899.6         $  105.3
                                                                     ==========         ========
  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 June
  30, 1999 and for the three and six months then ended are unaudited,  but include
  all adjustments  that PECO Energy Company  (Company)  considers  necessary for a
  fair presentation of such financial statements. All adjustments are of a normal,
  recurring nature.  The year-end condensed  consolidated  balance sheet data were
  derived from audited  financial  statements  but do not include all  disclosures
  required by generally accepted accounting principles. Certain prior-year amounts
  have been reclassified for comparative  purposes.  These notes should be read in
  conjunction with the Notes to Consolidated Financial Statements in the Company's
  1998 Annual Report to  Shareholders,  which are incorporated by reference in the
  Company's Annual Report on Form 10-K for the year ended December 31, 1998.
  
  2.       TRANSITION BONDS
           On March 25, 1999, PECO Energy  Transition Trust (PETT), an independent
  statutory business trust organized under the laws of Delaware and a wholly owned
  subsidiary  of the  Company,  issued $4 billion  aggregate  principal  amount of
  Transition  Bonds  (Transition  Bonds) to  securitize a portion of the Company's
  authorized  stranded cost recovery.  The Transition Bonds are solely obligations
  of PETT, secured by Intangible  Transition  Property sold by the Company to PETT
  concurrently  with the  issuance  of the  Transition  Bonds  and  certain  other
  collateral related thereto.
  
           The terms of the Transition Bonds are as follows:
  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               5.18% (a)       March 1, 2004              March 1, 2006
           A-4           $458.5               5.80%           March 1, 2005              March 1, 2007
           A-5           $464.6               5.26% (a)       September 1, 2007          March 1, 2009
           A-6           $993.4               6.05%           March 1, 2007              March 1, 2009
           A-7           $896.7               6.13%           September 1, 2008          March 1, 2009
  (a) The Class A-3 and A-5 Transition  Bonds earn interest at a floating
           rate.  The rates  provided for each such class above are as of June 30,
           1999.
  
                                         6
  The  Company  entered  into  treasury  forwards  and  forward  starting
  interest  rate  swaps to  manage  interest  rate  exposure  associated  with the
  anticipated  issuance of Transition  Bonds. On March 18, 1999, these instruments
  were settled with net proceeds to the Company of approximately $80 million which
  were deferred and are being amortized over the life of the Transition Bonds as a
  reduction of interest  expense,  consistent with the Company's hedge  accounting
  policy.
  
           The Company has entered  into  interest  rate swaps to manage  interest
  rate  exposure  associated  with the  issuance  of two  floating  rate series of
  Transition  Bonds. At June 30, 1999, the fair value of these instruments was $52
  million based on the present value difference between the contracted rate (i.e.,
  hedged rate) and the market rates at that date.  A  hypothetical  50 basis point
  increase or  decrease in the spot yield at June 30, 1999 would have  resulted in
  an aggregate  fair value of these  interest rate swaps of $91.2 million or $10.7
  million, respectively. If the derivative instruments had been terminated at June
  30, 1999,  these  estimated  fair values  represent the amount to be paid by the
  counterparties to the Company.
  
           The net proceeds to the Company from the securitization of a portion of
  its allowed  stranded cost recovery,  after payment of fees and expenses and the
  capitalization of PETT, were approximately $3.95 billion. In accordance with the
  provisions  of the  Pennsylvania  Electricity  Generation  Customer  Choice  and
  Competition  Act, the Company is utilizing these proceeds  principally to reduce
  its  stranded  costs and related  capitalization.  Through  June 30,  1999,  the
  Company  utilized the net proceeds to repurchase  38.7 million  shares of Common
  Stock for an aggregate purchase price of $1.507 billion; to retire: $811 million
  of First Mortgage  Bonds,  a $400 million term loan,  $208 million of commercial
  paper, $150 million of accounts receivable  financing and a $139 million capital
  lease  obligation;  to  repurchase $9 million of Company  Obligated  Mandatorily
  Redeemable  Preferred  Securities  of a  Partnership  (COMRPS);  and to pay  $25
  million of debt issuance costs.  The remaining  proceeds of  approximately  $750
  million are  included in cash at June 30, 1999.  In addition,  on July 30, 1999,
  the Company  redeemed  $212  million of COMRPS.  On August 2, 1999,  the Company
  retired $37 million of Mandatorily  Redeemable  Preferred  Stock pursuant to the
  sinking fund requirements of those securities.
  
           In the second  quarter of 1999, the Company  incurred an  extraordinary
  charge of $26.7 million,  net of tax,  consisting of prepayment premiums and the
  write-off of unamortized  deferred  financing  costs  associated  with the early
  retirement of debt.
  
  3.   SEGMENT INFORMATION
           The Company is primarily a vertically  integrated  public  utility that
  provides  retail  electric  and  natural  gas  service  to  the  public  in  its
  traditional  service territory and retail electric generation service throughout
  Pennsylvania  pursuant to Pennsylvania's  Customer Choice Program. The Company's
  management  has  historically  managed  the Company as a  vertically  integrated
  entity by analyzing its results of operations  on a  consolidated  basis with an
  emphasis on electric and gas operations.
  
            During the first quarter of 1999,  the Company  completed the redesign
  of its internal  reporting  structure to separate its distribution,  generation,
  
                                         7
  and  ventures   operations  into  business  units  and  provide   financial  and
  operational  data  on  the  same  basis  to  senior  management.  The  Company's
  distribution  business unit includes its electric  transmission and distribution
  services,   regulated  retail  sales  of  generation  services  and  retail  gas
  businesses. The Company's generation business unit includes the operation of its
  generation assets and its power marketing group. The Company's ventures business
  unit includes its unregulated  retail energy supplier,  infrastructure  services
  business and its telecommunications equity investments.
  
           During the second  quarter of 1999,  the  Company  further  revised the
  internal  reporting  structure to include its unregulated retail energy supplier
  with the  generation  business  unit to more  efficiently  manage the  Company's
  overall energy supply requirements.  Accordingly,  the results of operations and
  assets of the unregulated  retail energy supplier are included in the generation
  business unit for all periods presented.
  
           The  Company's  segment  information  as of and for the  three  and six
  months ended June 30, 1999 as compared to the same 1998 period is as follows (in
  millions of dollars):
  
  Quarter Ended June 30, 1999 as compared to the quarter ended June 30, 1998
  Intersegment
                      Distribution        Generation         Ventures       Corporate           Revenues         Consolidated
                      ------------        ----------         --------       ---------           --------         ------------
  Revenues:
      1999               $734.0             $653.2             $   .6           $    -          $(193.4)           $1,194.4
      1998               $905.5             $547.7             $   .7           $    -          $(238.7)           $1,215.2
  EBIT (a):
      1999               $298.2             $ 11.1            $( 15.1)         $( 44.7)                            $  249.5
      1998               $356.0             $ 61.0            $( 35.8)         $( 41.1)                            $  340.1
  
  Six Months Ended June 30, 1999 as compared to six months ended June 30, 1998
  
  Revenues:
      1999               $1,646.5           $1,197.9           $   1.2          $ -             $(394.8)           $2,450.8
      1998               $1,854.3           $1,029.6           $   1.3          $ -             $(479.8)           $2,405.4
  EBIT (a):
      1999               $655.7             $ 41.0(b)         $( 36.0)         $( 81.8)                            $  578.9
      1998               $663.5             $ 99.0            $( 59.5)         $( 87.9)                            $  615.1
  Total Assets:
      1999              $10,810.8(c)       $1,868.5            $240.2          $427.2                              $13,346.7
      1998              $ 9,723.6          $1,680.6            $216.1          $384.1                              $12,004.4
  (a) EBIT - Earnings Before Interest and Income Taxes.
   (b) Includes an $11.8 million reserve related to the Grays Ferry power purchase
   agreement and $14.6 million related to the write-off of the investment in Grays
   Ferry in connection with the settlement of litigation.
   (c) Includes $750 million of proceeds from securitization of stranded costs.
  8
  4.       EARNINGS PER SHARE
           Diluted  earnings per average  common share is  calculated  by dividing
  earnings  applicable  to common  stock by the  average  shares  of common  stock
  outstanding  after giving effect to stock options,  issuable under the Company's
  stock option plans,  considered  to be dilutive  common stock  equivalents.  The
  following  table  shows  the  effect  of the stock  options  issuable  under the
  Company's stock option plans on the average number of shares used in calculating
  diluted earnings per average common share (in millions of shares):
  Three Months Ended                   Six Months Ended
                                                                   June 30,                             June 30,
                                                            1999                  1998            1999               1998
                                                           -----                 -----            -----             -----
  Average Common Shares Outstanding                        192.0                 222.7            207.6             222.6
  
  Assumed Conversion of Stock Options                        1.5                    .7              1.5                .7
                                                           -----                 -----            -----             -----
  
  Potential Average Dilutive
    Common Shares Outstanding                              193.5                 223.4            209.1             223.3
                                                           =====                 =====            =====             =====
  5.       SALES OF ACCOUNTS RECEIVABLE
           The  Company is party to an  agreement  with a  financial  institution,
  under which it can sell or finance with limited recourse an undivided  interest,
  adjusted daily, in up to $275 million of designated  accounts  receivable  until
  November 2000. At June 30, 1999, the Company had sold a $275 million interest in
  accounts  receivable,   consisting  of  a  $232  million  interest  in  accounts
  receivable which the Company accounts for as a sale under Statement of Financial
  Accounting  Standards (SFAS) No. 125, "Accounting for Transfers and Servicing of
  Financial Assets and  Extinguishment of Liabilities," and a $43 million interest
  in special agreement accounts  receivable which are accounted for as a long-term
  note  payable.  The  Company  retains  the  servicing  responsibility  for these
  receivables.  The  agreement  requires  the Company to maintain the $275 million
  interest,  which,  if not met,  requires the Company to deposit cash in order to
  satisfy such requirements. The Company, at June 30, 1999, met such requirements.
  At June 30, 1999, the average annual  service-charge  rate,  computed on a daily
  basis on the portion of the accounts receivable sold but not yet collected,  was
  4.90%.
  
  6.       AMERGEN ENERGY COMPANY
           On April 15, 1999,  AmerGen Energy  Company,  LLC (AmerGen),  the joint
  venture between the Company and British Energy, plc (British Energy),  announced
  an interim  agreement to purchase the Clinton  Nuclear Power  Station  (Clinton)
  from  Illinois  Power (IP), a subsidiary  of Illinova  Corporation.  On June 30,
  1999,  AmerGen and British  Energy  signed a  definitive  agreement  to purchase
  Clinton from IP.  AmerGen has entered  into  agreements  to purchase  Three Mile
  Island Unit No.1  Nuclear  Generating  Facility,  Nine Mile Point Unit 1 Nuclear
  Generating  Facility  and 59% of  Nine  Mile  Point  Unit 2  Nuclear  Generating
  Facility.  In  addition,  the  Company  and IP  amended  the  January  15,  1998
  Management Agreement, providing for the provision of certain management services
  by the  Company  to IP in support  of  Clinton's  outage  recovery  efforts  and
  operations.
  
                                         9
  7.    CLINTON NUCLEAR POWER STATION
           Under the Amended  Management  Agreement,  effective April 1, 1999, the
  Company is responsible  for the payment of all direct  operating and maintenance
  (O&M)  costs and  direct  capital  costs  incurred  by IP and  allocable  to the
  operation of Clinton.  IP will  continue to pay  indirect  costs such as pension
  benefits,  payroll taxes and property  taxes.  Following the restart of Clinton,
  which  occurred on June 2, 1999,  and through  December 31, 1999, the Company is
  selling 80% of the output of Clinton to IP. The  remaining  output is being sold
  by the Company in the  wholesale  market.  Under a separate  agreement  with the
  Company,  British  Energy  has  agreed to share  50% of the  costs and  revenues
  associated with the Amended Management Agreement. In the second quarter of 1999,
  the Company  recognized  $14 million of revenue from sales to IP and $25 million
  of O&M expenses related to Clinton.
  
  8.       COMMITMENTS AND CONTINGENCIES
           For information  regarding the Company's capital  commitments,  nuclear
  insurance,  nuclear  decommissioning and spent fuel storage, energy commitments,
  environmental  issues  and  litigation,  see  note 5 of  Notes  to  Consolidated
  Financial Statements for the year ended December 31, 1998.
  
           At June 30,  1999,  the Company had entered into  long-term  agreements
  with  unaffiliated  utilities to purchase  transmission  rights.  These purchase
  commitments  result in  obligations  of  approximately  $50 million in 1999, $88
  million in 2000,  $51 million in 2001,  and $41 million in 2002,  $36 million in
  2003 and $97 million thereafter.
  
           The Company has identified 28 sites where former manufactured gas plant
  (MGP) activities have or may have resulted in actual site  contamination.  As of
  June  30,  1999,   the  Company  had  accrued  $59  million  for   environmental
  investigation and remediation costs, including $33 million for MGP investigation
  and remediation that currently can be reasonably  estimated.  The Company cannot
  predict  whether it will incur  other  significant  liabilities  for  additional
  investigation  and remediation  costs at these or additional sites identified by
  the Company, environmental agencies or others, or whether all such costs will be
  recoverable from third parties.
  
           On April 23, 1999, the Company and Grays Ferry Cogeneration Partnership
  (Grays Ferry)  entered into a final  settlement of  litigation.  The  settlement
  resulted in a restructuring of the power purchase  agreement between the Company
  and Grays Ferry.  The  settlement  also required the Company to  contribute  its
  interest in the partnership to the remaining partners.  Accordingly, the Company
  recorded  a  charge  to  earnings  of  $14.6  million  for the  transfer  of its
  partnership  interest  and a  reserve  of $11.8  million  related  to the  power
  purchase agreement. The charge for the partnership interest transfer is recorded
  in Other  Income  and  Deductions  and the  reserve  related  to power  purchase
  agreement is recorded in Fuel and Energy  Interchange  Expense on the  Company's
  Statement of Income for the six months ended June 30, 1999. The settlement  also
  resolved  the  litigation  with  Westinghouse  Power  Generation  and The  Chase
  Manhattan Bank.
  
                                         10
  9.       NEW ACCOUNTING PRONOUNCEMENTS
           In June 1998, the Financial  Accounting  Standards  Board (FASB) issued
  SFAS No. 133,  "Accounting for Derivative  Instruments and Hedging  Activities,"
  (SFAS No. 133) to establish  accounting and reporting standards for derivatives.
  The new  standard  requires  recognizing  all  derivatives  as either  assets or
  liabilities  on the  balance  sheet  at  their  fair  value  and  specifies  the
  accounting  for changes in fair value  depending  upon the  intended  use of the
  derivative.  In June  1999,  the  FASB  issued  SFAS  No.  137  "Accounting  for
  Derivative  Instruments and Hedging  Activities - Deferral of the Effective Date
  of FASB  Statement No. 133," (SFAS No. 137) which delayed the effective date for
  SFAS No. 133 until  fiscal  years  beginning  after June 15,  2000.  The Company
  expects to adopt SFAS No. 133 in the first  quarter of 2001.  The  Company is in
  the  process  of  evaluating  the  impact  of  SFAS  No.  133 on  its  financial
  statements.
  
           In November 1998, the FASB's  Emerging  Issues Task Force (EITF) issued
  EITF  98-10,  "Accounting  for  Contracts  Involved  in Energy  Trading and Risk
  Management Activities." EITF 98-10 outlines attributes that may be indicative of
  an energy  trading  operation and gives further  guidance on the  accounting for
  contracts entered into by an energy trading operation.  This accounting guidance
  requires  mark-to-market  accounting  for  contracts  considered to be a trading
  activity. EITF 98-10 is applicable for fiscal years beginning after December 15,
  1998 with any impact recorded as a cumulative effect adjustment through retained
  earnings at the date of adoption.
  
           The Company's wholesale  marketing  operations enter into long-term and
  short-term  commitments to purchase and sell energy and energy-related  products
  with the intent and ability to deliver or take  delivery.  The  objective of the
  long-term  commitments is to establish a generation base that allows the Company
  to meet the  physical  supply and demand  requirements  of a national  wholesale
  electric marketplace through scheduled,  real-time delivery of electricity.  The
  Company utilizes  short-term energy  commitments and contracts,  entered into in
  the  over-the-counter  market,  to  economically  hedge seasonal and operational
  risks associated with peak demand periods and generation plant outages.
  
           The Company  reviewed  the  criteria  indicative  of an energy  trading
  operation  as outlined in EITF 98-10  against the  objectives  and intent of the
  Company's wholesale marketing operation's activities. The Company concluded that
  none of the  activities of its marketing  operation are trading  activities  and
  therefore  these  activities  are not  subject to EITF  98-10 or  mark-to-market
  accounting.
  
           The Company  records  revenues and expenses  associated with the energy
  commitments   at  the  time  the   underlying   physical   transaction   closes.
  Additionally,  the Company evaluates its energy commitments for impairment based
  on the lower of cost or market.  At June 30, 1999, the Company concluded that no
  energy commitments were impaired.
  
                                         11
  ITEM 2.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
  RESULTS OF OPERATIONS
  
  GENERAL
  
           Retail   competition   for  electric   generation   services  began  in
  Pennsylvania on January 1, 1999. As of January 2, 1999, two-thirds of each class
  of the Company's retail electric customers in its traditional  service territory
  have a right to choose their generation  suppliers.  Effective  January 2, 2000,
  all of the  Company's  retail  electric  customers  in its  traditional  service
  territory will have the right to choose their generation suppliers.  At June 30,
  1999,   approximately  239,000  customers  representing  15%  of  the  Company's
  residential customers, 25% of its commercial customers and 58% of its industrial
  customers had selected an alternate  energy  supplier.  As of that date,  Exelon
  Energy,  the Company's  alternative  energy  supplier,  was  providing  electric
  generation service to approximately  141,000 business and residential  customers
  located throughout Pennsylvania.
  
           Effective  January 1, 1999,  the Company  reduced  its retail  electric
  rates for all customers by 8%. On that date,  the Company began  recovering  its
  stranded costs through the collection of competitive transition charges from all
  customers.  On March 25, 1999,  PECO Energy  Transition  Trust (PETT),  a wholly
  owned  subsidiary  of the Company,  issued $4 billion of PECO Energy  Transition
  Trust  Transition  Bonds to securitize a portion of the Company's  stranded cost
  recovery.  In accordance with the terms of the  Competition  Act, the Company is
  utilizing the proceeds from the issuance of the Transition Bonds  principally to
  reduce stranded costs and capitalization.
  
           The Company currently  estimates that the impact of additional interest
  expense  associated  with the  Transition  Bonds  partially  offset by  interest
  savings  related to higher cost debt  retired  with  Transition  Bond  proceeds,
  combined  with the  anticipated  reduction  in  common  equity,  will  result in
  earnings  per share  benefits of  approximately  $.15 and $.50 in 1999 and 2000,
  respectively.  These  estimated  earnings per share could change and are largely
  dependent upon the timing and price of common stock  repurchases and anticipated
  net income available to common stock.
  
           The Company  expects  that  competition  for both retail and  wholesale
  generation services will substantially  affect its future results of operations.
  See "Management's  Discussion and Analysis of Financial Condition and Results of
  Operations - Outlook,"  incorporated by reference in the Company's Annual Report
  on Form 10-K for the year ended December 31, 1998.
  
           The   Company's   internal   reporting   structure   consists   of  its
  distribution,  generation,  and ventures operations.  The Company's distribution
  business  unit includes its electric  transmission  and  distribution  services,
  regulated  retail sales of generation  services and retail gas  businesses.  The
  Company's  generation  business unit  includes the  operation of its  generation
  assets,  its power marketing group and its unregulated  retail energy  supplier.
  The  Company's  ventures  business  unit  includes its  infrastructure  services
  business and its telecommunications equity investments.
  
                                         12
  RESULTS OF OPERATIONS
  
           The Company's Condensed Consolidated Statements of Income for the three
  and six months ended June 30, 1998 reflect the  reclassification  of the results
  of operations of Exelon Energy, from Other Income and Deductions.
  
           Under its  Amended  Management  Agreement  with  Illinois  Power  (IP),
  effective  April 1, 1999,  the  Company is  responsible  for the  payment of all
  direct  operating and maintenance  (O&M) costs and direct capital costs incurred
  by IP and allocable to the operation of Clinton Nuclear Power Station (Clinton).
  IP will continue to pay indirect costs such as pension  benefits,  payroll taxes
  and property  taxes.  Following the restart of Clinton,  which  occurred on June
  2,1999,  and through December 31, 1999, the Company is selling 80% of the output
  of  Clinton  to IP. The  remaining  output is being  sold by the  Company in the
  wholesale market.  Under a separate  agreement with the Company,  British Energy
  has agreed to share 50% of the costs and  revenues  associated  with the Amended
  Management Agreement.
  Revenue and Expense Items as a
  Percentage of Total Operating
  Revenues                                                                 Percentage Dollar Changes
                                                                                 1999 vs. 1998
          Quarter           Six Months                                       Quarter        Six Months
           Ended               Ended                                          Ended           Ended
          June 30,            June 30,                                       June 30,       June 30,
      1999      1998        1999   1998
  93%       93%         87%    89%      Electric                          (2%)           --%
        7%        7%         13%    11%      Gas                                7%            13%
      ----      ----        ----   ----
      100%      100%        100%   100%      Total Operating Revenues          (2%)            2%
      ----      ----        ----   ----
  
       42%       30%         39%    31%      Fuel and Energy Interchange       39%            30%
       28%       21%         26%    22%      Operating and Maintenance         32%            16%
        5%       13%          5%    13%      Depreciation and Amortization    (64%)          (64%)
        4%        6%          5%     6%      Taxes Other Than Income          (37%)          (22%)
      ----      ----        ----   ----
       79%       70%         75%    72%      Total Operating Expenses          11%             4%
      ----      ----        ----   ----
  
       21%       30%         25%    28%      Operating Income                 (31%)           (5%)
      ----      ----        ----   ----
  
      (10%)      (8%)        (8%)   (8%)     Interest Charges                  28%             8%
      ( 1%)      (2%)        (2%)   (2%)     Other Income and Deductions      (83%)           17%
      ----      ----        ----   ----
  
                                             Income Before Income Taxes and
       10%       20%         15%    18%        Extraordinary Item             (48%)          (12%)
        3%        8%          6%     7%      Income Taxes                     (57%)          (15%)
      ----      ----        ----   ----
        7%       12%          9%    11%      Income Before Extraordinary Item
       (2%)       --         (1%)    --      Extraordinary Item               100%            --%
      ----      ----        ----   ----
        5%       12%          8%    11%   Net Income                          (60%)          (21%)
      ====      ====        ====   ====
  13
  Second Quarter 1999 Compared To Second Quarter 1998
  Operating Revenues
           Electric revenues  decreased $26 million,  or 2%, for the quarter ended
  June 30, 1999  compared to the same 1998  period.  The  decrease  was  primarily
  attributable  to lower  revenues  from the  distribution  business  unit of $176
  million partially offset by higher revenues from the generation business unit of
  $150 million. The decrease from the distribution  business unit was attributable
  to $136  million  as a result of lower  volume  associated  with the  effects of
  competition,  $65  million  related to the 8%  across-the-board  rate  reduction
  mandated by the Final  Restructuring  Order and $12 million related to decreased
  sales  volume  from  milder  weather  conditions  as  compared to the prior year
  comparable  period.  These decreases were partially offset by $37 million of PJM
  Interconnection,  LLC (PJM) network transmission service revenue which commenced
  April 1, 1998.  PJM network  transmission  service  revenues  and  charges  were
  recorded in the generation business unit in 1998 but are being recognized by the
  distribution  business unit in 1999 as a result of the Federal Energy Regulatory
  Commission  approval  of  the  PJM  Regional   Transmission  Owners'  rate  case
  settlements. Stranded cost recovery is included in the Company's retail electric
  rates beginning January 1, 1999. The increase from the generation  business unit
  was attributable to $117 million from increased volume in Pennsylvania resulting
  from the sale of  competitive  electric  generation  services by Exelon  Energy,
  increased  wholesale  revenues  of $58  million  from the  marketing  of  excess
  generation  capacity as a result of retail  competition and $14 million from the
  sale of generation  from Clinton to IP,  partially  offset by $39 million of PJM
  network transmission service revenue in the comparable period.
  
           Gas revenues  increased $6 million,  or 7%, for the quarter  ended June
  30,  1999  compared  to  the  same  1998  period.  The  increase  was  primarily
  attributable  to $4 million from increased  volume as a result of cooler weather
  conditions in the beginning of the quarter and $2 million from increased  volume
  from new and existing customers.
  
  Fuel and Energy Interchange Expense
           Fuel and energy interchange expense increased $140 million, or 39%, for
  the  quarter  ended  June 30,  1999  compared  to the  same  1998  period.  As a
  percentage of revenue, fuel and interchange expenses were 42% as compared to 30%
  in the comparable prior year period. These increases were attributable to higher
  fuel and energy  interchange  expenses  associated with the generation  business
  unit of $83 million  and the  distribution  business  unit of $57  million.  The
  increase from the generation  business unit was primarily  attributable  to $129
  million related to increased  volume from Exelon Energy sales,  partially offset
  by lower PJM network  transmission service charges of $39 million and $3 million
  of fuel  savings  associated  with the  full  return  to  service  of the  Salem
  Generating  Station  (Salem) in April 1998 which  decreased the need to purchase
  power to replace the output from these units. The increase from the distribution
  business  unit was  attributable  to $24  million  of PJM  network  transmission
  service charges,  $46 million of purchases in the spot market and $10 million of
  additional  gas  purchases as a result of higher volume  associated  with cooler
  weather  early  in  the  quarter  and  additional  volume  to new  and  existing
  customers.  These  increases were partially  offset by $23 million of lower fuel
  costs primarily as a result of lower volume associated with Customer Choice.
  
                                         14
  Operating and Maintenance Expense
           Operating and maintenance (O&M) expense  increased $83 million,  or 32%
  for the quarter  ended June 30,  1999  compared  to the same 1998  period.  As a
  percentage of revenue,  operating and maintenance  expenses were 28% as compared
  to 21% in the comparable prior year period.  The generation  business unit's O&M
  expenses increased $58 million as a result of $25 million related to the revised
  Clinton  management  agreement,  $15 million associated with the Salem inventory
  write-off  and true-up of 1998  reimbursement  of  joint-owner  expenses and $15
  million related to the growth of unregulated  retail sales of  electricity.  The
  distribution unit's O&M expenses increased approximately $22 million as a result
  of additional  marketing expenses and expenses  associated with Customer Choice.
  In addition,  the Company incurred additional costs of approximately $11 million
  related to nuclear property  insurance and $4 million  associated with Year 2000
  remediation expenditures,  partially offset by $10 million of pension credits as
  a result of the performance of the investments in the Company's pension plan.
  
  Depreciation and Amortization Expense
           Depreciation and amortization  expense decreased $103 million,  or 64%,
  for the quarter  ended June 30,  1999  compared  to the same 1998  period.  As a
  percentage of revenue,  depreciation and amortization expense was 5% as compared
  to 13% in the comparable prior year period. The decrease was associated with the
  December  1997  restructuring  charge  through  which the  Company  wrote down a
  significant portion of its generating plant and regulatory assets. In connection
  with this restructuring charge, the Company reduced generation-related assets by
  $8.4  billion,   established  a  regulatory  asset,  Deferred  Generation  Costs
  Recoverable in Current Rates of $424 million, which was fully amortized in 1998,
  and established an additional  regulatory asset,  Competitive  Transition Charge
  (CTC) of $5.26 billion  which will begin to be amortized in accordance  with the
  terms of the Final Restructuring Order in 2000. For additional information,  see
  "PART I, ITEM 1. - BUSINESS -  Deregulation  and Rate Matters," in the Company's
  1998 Annual Report on Form 10-K.
  
  Taxes Other Than Income
           Taxes other than income decreased $27 million,  or 37%, for the quarter
  ended  June 30,  1999  compared  to the same 1998  period.  As a  percentage  of
  revenue,  taxes other than income were 4%, as compared to 6%, in the  comparable
  prior year  period.  The decrease was  primarily  attributable  to a $26 million
  credit related to an adjustment to the Company's  Pennsylvania capital stock tax
  base as a result of the 1997  restructuring  charge and lower gross receipts tax
  of $3 million associated with lower retail electric and gas sales.
  
  Interest Charges
           Interest charges consist of interest expense,  distributions on Company
  Obligated Mandatorily  Redeemable Preferred Securities of a Partnership (COMPRS)
  and  Allowance  for Funds Used During  Construction  (AFUDC).  Interest  charges
  increased  $26 million,  or 28%, for the quarter ended June 30, 1999 compared to
  the same 1998 period.  As a percentage of revenue,  interest charges were 10% as
  compared to 8% in the comparable  prior year period.  The increase was primarily
  attributable  to  interest on the  Transition  Bonds of $60  million,  partially
  offset by the Company's  ongoing program to reduce and/or refinance higher cost,
  long-term debt, including the use of a portion of the proceeds from the issuance
  of Transition Bonds, which reduced interest charges by $34 million.
  
                                         15
  Other Income and Deductions
           Other income and deductions excluding interest charges was a loss of $5
  million for the quarter ended June 30, 1999 as compared to a loss of $27 million
  in the same 1998 period. The decrease of $22 million was primarily  attributable
  to a $10 million write-off of a non-regulated business venture in the prior year
  period and a $5 million  improvement in the performance of the Company's  equity
  investments in telecommunications.
  
  Income Taxes
           The  effective  tax rate was 32% for the quarter ended June 30, 1999 as
  compared to 38% in the same 1998 period.  The decrease in the effective tax rate
  was a result of tax benefits  associated  with the  implementation  of state tax
  planning  strategies,  partially offset by the  non-recognition for state income
  tax purposes of certain  operating  losses.  In addition,  the  disproportionate
  relationship  of regulated  plant tax  adjustments to income before income taxes
  and extraordinary item contributed to the decrease in the effective tax rate.
  
  Extraordinary Item
           During  the  second   quarter  of  1999,   the   Company   incurred  an
  extraordinary  charge of $26.7  million,  net of tax,  consisting  of prepayment
  premiums and the write-off of unamortized  deferred  financing costs  associated
  with the  early  retirement  of debt  with a portion  of the  proceeds  from the
  issuance of Transition Bonds.
  
  Preferred Stock Dividends
           Preferred  stock  dividends  for the  quarter  ended June 30, 1999 were
  consistent with the same 1998 period.
  
  Six Months Ended June 30, 1999 Compared to Six Months Ended June 30, 1998
  Operating Revenues
           Electric  revenues  increased $10 million for the six months ended June
  30,  1999  compared  to  the  same  1998  period.  The  increase  was  primarily
  attributable  to  higher  revenues  from the  generation  business  unit of $256
  million  partially offset by lower revenues from the distribution  business unit
  of $246 million. The increase from the generation business unit was attributable
  to $204 million from increased volume in Pennsylvania resulting from the sale of
  competitive  electric generation services by Exelon Energy,  increased wholesale
  revenues of $77 million from the  marketing of excess  generation  capacity as a
  result of retail  competition  and $14 million from the sale of generation  from
  Clinton  to IP,  partially  offset by $39  million of PJM  network  transmission
  service  revenue  in  the  comparable   1998  period.   The  decrease  from  the
  distribution business unit was attributable to $205 million as a result of lower
  volume  associated  with the  effects  of retail  competition  and $120  million
  related  to  the 8%  across-the-board  rate  reduction  mandated  by  the  Final
  Restructuring Order. These decreases were partially offset by $74 million of PJM
  network  transmission  service revenue and $5 million related to increased sales
  volume as a result of colder  weather  conditions  in the first  quarter of 1999
  partially  offset by milder weather  conditions in the second quarter of 1999 as
  compared to the prior year periods.
  
                                         16
  Gas revenues  increased  $36 million,  or 13%, for the six months ended
  June 30, 1999  compared to the same 1998  period.  The  increase  was  primarily
  attributable to $24 million from increased  volume as a result of cooler weather
  conditions  in the  beginning of the period as compared to the prior year period
  and $12 million from increased volume from new and existing customers.
  
  Fuel and Energy Interchange Expense
           Fuel and energy interchange expense increased $222 million, or 30%, for
  the six months  ended  June 30,  1999  compared  to the same 1998  period.  As a
  percentage of revenue, fuel and interchange expenses were 39% as compared to 31%
  in the comparable prior year period. These increases were attributable to higher
  fuel and energy interchange  expenses associated with the distribution  business
  unit of $119  million and the  generation  business  unit of $103  million.  The
  increase from the distribution  business unit was primarily  attributable to $51
  million of PJM network transmission service charges, $99 million of purchases in
  the spot  market and $21  million of  additional  gas  purchases  as a result of
  higher volume  associated with cooler weather early in the period and additional
  volume to new and existing  customers.  These increase were partially  offset by
  $55  million  of lower fuel costs as a result of lower  volume  associated  with
  Customer  Choice.  The increase from the generation  business unit was primarily
  attributable  to $200  million  related to increased  volume from Exelon  Energy
  sales,  partially offset by $45 million of lower fuel costs as a result of lower
  volume,  lower PJM network  transmission service charges of $39 million, and $19
  million of fuel savings  associated with the full return to service of the Salem
  Generating  Station  (Salem) in April 1998 which  decreased the need to purchase
  power to replace the output from these units.
  
  Operating and Maintenance Expense
           O&M expense increased $88 million, or 16% for the six months ended June
  30, 1999 compared to the same 1998 period. As a percentage of revenue, operating
  and  maintenance  expenses were 26% as compared to 22% in the  comparable  prior
  year period.  The generation  business unit's O&M expenses increased $50 million
  as a result of $25 million related to the revised Clinton management  agreement,
  $15 million  associated with the Salem  inventory  write-off and true-up of 1998
  reimbursement  of joint-owner  expenses and $10 million related to the growth of
  unregulated  retail  sales of  electricity,  partially  offset by $10 million of
  lower O&M  expenses  as a result of the full return to service of Salem in April
  1998. The distribution  unit's O&M expenses increased  approximately $22 million
  as a result of  additional  marketing  expenses  and  expenses  associated  with
  Customer  Choice.  In  addition,   the  Company  incurred  additional  costs  of
  approximately $11 million related to nuclear property  insurance and $16 million
  associated  with Year 2000  remediation  expenditures,  partially  offset by $10
  million of pension  credits as a result of the performance of the investments in
  the Company's pension plan.
  
  Depreciation and Amortization Expense
           Depreciation and amortization  expense decreased $202 million,  or 64%,
  for the six months ended June 30, 1999  compared to the same 1998  period.  As a
  percentage of revenue,  depreciation and amortization expense was 5% as compared
  to 13% in the comparable prior year period. The decrease was associated with the
  December  1997  restructuring  charge  through  which the  Company  wrote down a
  significant portion of its generating plant and regulatory assets.
  
                                         17
  Taxes Other Than Income
           Taxes other than income  decreased  $33  million,  or 22%,  for the six
  months ended June 30, 1999 compared to the same 1998 period.  As a percentage of
  revenue,  taxes other than income were 5%, as compared to 6%, in the  comparable
  prior year  period.  The decrease was  primarily  attributable  to a $30 million
  credit related to an adjustment to the Company's  Pennsylvania capital stock tax
  base as a result of the 1997  restructuring  charge and lower gross receipts tax
  of $6 million associated with lower retail electric and gas sales.
  
  Interest Charges
           Interest charges increased $15 million, or 8%, for the six months ended
  June 30, 1999  compared to the same 1998  period.  As a  percentage  of revenue,
  interest  charges were  comparable  to the prior year period at 8%. The increase
  was primarily  attributable to interest on the Transition  Bonds of $60 million,
  partially  offset by the Company's  ongoing  program to reduce and/or  refinance
  higher cost, long-term debt, including the use of a portion of the proceeds from
  the issuance of Transition Bonds, which reduced interest charges by $45 million.
  
  Other Income and Deductions
           Other income and deductions  excluding  interest  charges was a loss of
  $47 million for the six months  ended June 30, 1999 as compared to a loss of $40
  million  in the same 1998  period.  The  increase  of $7 million  was  primarily
  attributable  to a $15 million  write-off  of the  investment  in Grays Ferry in
  connection  with the  settlement  of  litigation,  and a charge  related  to the
  abandonment of an information  system of $7 million,  partially  offset by a $10
  million  write-off of a non-regulated  business venture in the prior year period
  and a $3  million  improvement  in  the  performance  of  the  Company's  equity
  investments in telecommunications ventures.
  
  Income Taxes
           The  effective  tax rate was 37% for the six months ended June 30, 1999
  as compared to 38% in the same 1998 period.  The decrease in the  effective  tax
  rate was a result of tax benefits  associated with the  implementation  of state
  tax  planning  strategies,  partially  offset by the  non-recognition  for state
  income  tax   purposes  of  certain   operating   losses.   In   addition,   the
  disproportionate  relationship  of  regulated  plant tax  adjustments  to income
  before income taxes and  extraordinary  item  contributed to the decrease in the
  effective tax rate.
  
  Extraordinary Item
           During  the  second   quarter  of  1999,   the   Company   incurred  an
  extraordinary  charge of $26.7  million,  net of tax,  consisting  of prepayment
  premiums and the write-off of unamortized  deferred  financing costs  associated
  with the  early  retirement  of debt  with a portion  of the  proceeds  from the
  issuance of Transition Bonds.
  
  Preferred Stock Dividends
       Preferred  stock  dividends  for the six months  ended  June 30,  1999 were
  consistent with the same 1998 period.
  
                                         18
  DISCUSSION OF LIQUIDITY AND CAPITAL RESOURCES
           Cash flows provided by operating  activities  decreased $258 million to
  $252  million for the six months ended June 30, 1999 as compared to $510 million
  in the same 1998 period.  The decrease was primarily  attributable  to less cash
  generated by  operations  of $192 million and changes in working  capital of $62
  million,  principally  related to accounts  receivable from  unregulated  energy
  sales.
  
           Cash flows used by investing  activities  were $279 million for the six
  months  ended June 30, 1999 as compared to $265 million in the  comparable  1998
  period and consisted primarily of capital expenditures for plant.
  
           Cash flows provided by financing  activities  were $879 million for the
  six months ended June 30, 1999, as compared to cash used in financing activities
  of  $173  million  in  the  comparable  prior  year  period.  The  increase  was
  attributable to the issuance of $4 billion of Transition Bonds by PETT partially
  offset by the  repayment of  short-term  and  long-term  debt  aggregating  $1.5
  billion and the  application of $1.5 billion of Transition  Bond proceeds to the
  repurchase of common stock,  including  the  settlement of the Company's  common
  stock forward purchase contract.
  
           On March 25, 1999,  PETT issued $4 billion of its  Transition  Bonds to
  securitize a portion of the Company's  authorized  stranded cost  recovery.  The
  Transition  Bonds are solely  obligations  of PETT,  secured  by the  Intangible
  Transition  Property  (ITP) sold by the  Company to PETT.  Upon  issuance of the
  Transition  Bonds,  a  portion  of  the  competitive  transition  charges  to be
  collected by the Company to recover  stranded costs was designated as Intangible
  Transition Charges (ITC). The ITC is an irrevocable  non-bypassable  usage based
  charge that is  calculated  to allow for the  recovery of debt service and costs
  related to the issuance of the Transition  Bonds. The ITC will be allocated from
  CTC and variable distribution charges (both of which are usage based charges).
  
           PETT used the $3.95  billion of  proceeds  of the  Transition  Bonds to
  purchase the ITP from the  Company.  Although  the  Transition  Bonds are solely
  obligations of PETT, they are included in the consolidated long-term debt of the
  Company.  In accordance  with the terms of the  Competition  Act, the Company is
  utilizing the proceeds  principally to reduce stranded costs and capitalization.
  The  Company  currently  plans to reduce  its  capitalization  in the  following
  proportions: fixed and floating-rate debt, 50%; preferred securities, 7%; common
  equity,  43%.  Through June 30, 1999,  the Company  utilized the net proceeds to
  repurchase  38.7 million shares of Common Stock for an aggregate  purchase price
  of $1.507  billion;  to retire:  $811 million of First  Mortgage  Bonds,  a $400
  million term loan,  $208 million of commercial  paper,  $150 million of accounts
  receivable financing and a $139 million capital lease obligation;  to repurchase
  $9 million of Company Obligated Mandatorily Redeemable Preferred Securities of a
  Partnership  (COMRPS);  and to pay $25  million  of  debt  issuance  costs.  The
  remaining  proceeds of  approximately  $750 million are included in cash at June
  30, 1999. In addition,  on July 30, 1999,  the Company  redeemed $212 million of
  COMRPS.  On August 2, 1999,  the  Company  retired  $37  million of  Mandatorily
  Redeemable  Preferred  Stock pursuant to the sinking fund  requirements of those
  securities.  The  Company  currently  anticipates  that  it  will  complete  the
  repurchase of common equity  through open market  purchases from time to time in
  compliance with Securities and Exchange  Commission  rules. The number of shares
  purchased  and the timing and manner or  purchases  are  dependent  upon  market
  conditions.
  
                                         19
  Although the Company has sold the ITP to PETT, the ITC revenue, as well
  as all interest expense and amortization  expense associated with the Transition
  Bonds,  is  reflected on the  Company's  Consolidated  Statement of Income.  The
  combined  schedule for  amortization  of the CTC and ITC assets is in accordance
  with the amortization  schedule set forth in the Final Restructuring Order. As a
  result  of the  issuance  of the  Transition  Bonds  and  the  on-going  capital
  reduction by the Company, the Company expects its debt-to-total capital ratio to
  be 60%, exclusive of the Transition Bonds, upon completion of the application of
  the proceeds  from  securitization.  The Company  completed  the majority of the
  targeted debt and preferred  security  reductions by August 2, 1999, and expects
  that the  remaining  reductions  will be completed  by December  31,  1999.  The
  weighted  average  cost  of debt  and  preferred  securities  to be  retired  is
  approximately   6.8%.  The  additional  interest  expense  associated  with  the
  Transition Bonds, which have an effective  interest rate of approximately  5.8%,
  will be partially offset by the anticipated interest savings associated with the
  debt and  preferred  securities  that will be  retired.  The  Company  currently
  estimates  that  the  impact  of this  additional  expense,  combined  with  the
  anticipated  reduction  in common  equity,  will  result in  earnings  per share
  benefits of approximately  $.15 and $.50 in 1999 and 2000,  respectively.  These
  estimated  earnings  per share could change and are largely  dependent  upon the
  timing  and  price of  common  stock  repurchases  and  anticipated  net  income
  available to common stock.
  
           At June 30,  1999,  the Company had  outstanding  $226 million of notes
  payable, all of which were commercial paper. In addition,  at June 30, 1999, the
  Company had formal and informal lines of bank credit  aggregating  $100 million.
  At June 30, 1999, the Company had no short-term investments.
  
           On May 3, 1999, Standard & Poor's upgraded its ratings on the Company's
  overall corporate credit to "A-" from "BBB+", first and refunding mortgage bonds
  and  collateralized  medium-term  notes to "A"  from  "BBB+",  hybrid  preferred
  securities, capital trust securities and preferred stock to "BBB" from "BBB-".
  
  YEAR 2000 READINESS DISCLOSURE
           The Year 2000 Project (Y2K Project) is addressing  the issue  resulting
  from  computer  programs  using  two  digits  rather  than  four to  define  the
  applicable   year  and  other   programming   techniques   that  constrain  date
  calculations or assign special  meanings to certain dates.  Any of the Company's
  computer  systems  that have  date-sensitive  software  or  microprocessors  may
  recognize  a date using "00" as the year 1900  rather  than the year 2000.  This
  could  result in a system  failure or  miscalculations  causing  disruptions  of
  operations,  including,  a temporary  inability  to process  transactions,  send
  bills,  operate  generating  stations,  or engage  in  similar  normal  business
  activities.  Due to the severity of the potential  impact of the Year 2000 Issue
  (Y2K  Issue)  on  the  electric   utility   industry,   the  Company  adopted  a
  comprehensive  schedule to achieve Y2K  readiness  by the time  specified by the
  Nuclear  Regulatory  Commission  (NRC).  The  Company  has  dedicated  extensive
  resources to the Project and believes it is progressing on schedule.
  
                                         20
  The  Company  determined  that it was  required  to modify,  convert or
  replace significant portions of its software and a subset of its system hardware
  and embedded technology so that its computer systems will properly utilize dates
  beyond  December  31,  1999.  The  Company  presently  believes  that with these
  modifications,  conversions and  replacements the effect of the Y2K Issue on the
  Company can be mitigated.  If such  modifications,  conversions and replacements
  are not made, or are not completed in a timely manner,  the Y2K Issue could have
  a material impact on the operations and financial condition of the Company.  The
  costs associated with this potential impact are not presently quantifiable.  The
  Company is  utilizing  both  internal and external  resources to  reprogram,  or
  replace and test software and computer systems for the Project.  The Project was
  scheduled  for  completion  by July  1,  1999,  except  for a  small  number  of
  modifications,  conversions  or  replacements  that are impacted by PUC changes,
  vendor dates and/or are being  incorporated into scheduled plant outages between
  July and November 1999. The scheduled Project  completion date was met, with the
  limited anticipated exceptions noted above.
  
           The  Project  is  divided  into  four  major   sections  -  Information
  Technology Systems (IT Systems),  Embedded  Technology (devices used to control,
  monitor or assist the operation of equipment,  machinery or plant), Supply Chain
  (third-party  suppliers and customers),  and Contingency  Planning.  The general
  phases common to the first two sections  are: (1)  inventorying  Y2K items;  (2)
  assigning  priorities  to identified  items;  (3) assessing the Y2K readiness of
  items  determined to be material to the Company;  (4) converting  material items
  that are determined not to be Y2K ready;  (5) testing  material  items;  and (6)
  designing and implementing  contingency plans for each critical Company process.
  Material  items are those  believed by the Company to have a risk  involving the
  safety of  individuals,  may cause  damage to  property or the  environment,  or
  affect revenues.
  
           The IT Systems  section  includes both the  conversion of  applications
  software that is not Y2K ready and the  replacement  of software when  available
  from the supplier.  The Project has identified 363 critical systems of which 234
  are IT Systems and 129  Embedded  Systems.  The current  readiness  status of IT
  Systems is set forth below:
  
  Number of Systems Progress Status
  
  233 Systems                Y2K Ready
   1  System                 In Testing
  
  Contingency planning for IT Systems has been completed.
  
           The  remaining  129  systems are the  Embedded  Systems  consisting  of
  hardware  and  systems  software  other than IT Systems.  The current  readiness
  status of those systems is set forth below:
  
  Number of Systems Progress Status
  
  120 Systems                Y2K Ready
   9  Systems                In Progress
  
  Contingency planning for Embedded Technology has been completed.
  
                                         21
  The Supply  Chain  section  includes  the  process of  identifying  and
  prioritizing  critical  suppliers and communicating  with them about their plans
  and progress in addressing  the Y2K Issue.  The process of  evaluating  critical
  suppliers was completed on March 31, 1999. The Company has completed contingency
  plans for all critical suppliers.
  
           In addition to addressing  contingency  plans with key  suppliers,  the
  Company is currently  developing  contingency plans to address how to respond to
  internal  events which may disrupt  normal  operations.  These plans address Y2K
  risk  scenarios  that cross  departments  and business  units.  Emergency  plans
  already exist that cover various aspects of the Company's business.  These plans
  are being  reviewed  and updated to address  the Y2K Issue.  The Company is also
  participating in industry contingency planning efforts.
  
           The estimated total cost of the Project is $75 million, the majority of
  which is attributable to testing.  This estimate includes the Company's share of
  Y2K costs for jointly owned facilities. The total amount expended on the Project
  through June 30, 1999 was $44 million.  The Company  expects to fund the Project
  from  operating  cash  flows.  The  Company's  failure to become Y2K ready could
  result in an interruption in or a failure of certain normal business  activities
  or operations.  In addition, there can be no assurance that the systems of other
  companies on which the  Company's  systems  rely or with which they  communicate
  will be  converted in a timely  manner,  or that a failure to convert by another
  company,  or a conversion that is incompatible with the Company's systems,  will
  not  have  a  material  adverse  effect  on the  Company.  Such  failures  could
  materially and adversely affect the Company's  results of operations,  liquidity
  and financial condition.  The Company is currently developing  contingency plans
  to  address  how to  respond  to  events  that may  disrupt  normal  operations,
  including  activities  with PJM.  The costs of the Project and the date on which
  the Company plans to complete the Y2K modifications are based on estimates, that
  were derived  utilizing  numerous  assumptions of future  events,  including the
  continued availability of certain resources,  third-party modification plans and
  other factors,  such as regulatory  requirements that impact key systems.  There
  can be no assurance that these estimates will be achieved.  Actual results could
  differ  materially  from the  projections.  Specific  factors that might cause a
  material change include,  but are not limited to, the  availability  and cost of
  trained  personnel,  the  ability to locate and correct  all  relevant  computer
  programs and microprocessors.
  
           The Project is expected to significantly  reduce the Company's level of
  uncertainty about the Y2K Issue. The Company believes that the completion of the
  Project, as scheduled, minimizes the possibility of significant interruptions of
  normal operations.
  
           On July 17, 1998, an order was entered by the PUC  instituting a formal
  investigation  by the Office of  Administrative  Law on Year 2000  compliance by
  jurisdictional  fixed utilities and  mission-critical  service providers such as
  the PJM (the  Investigation).  The order requires,  (1) a written  response to a
  list  of  compliance   program   questions  by  August  6,  1998  and,  (2)  all
  jurisdictional fixed utilities be Year 2000 compliant by March 31, 1999 or, if a
  utility determines that  mission-critical  systems cannot be Year 2000 compliant
  on or before  March  31,  1999,  the  utility  is  required  to file a  detailed
  contingency plan. The PUC adopted the federal  government's  definition for Year
  2000  compliance and further  defined Year 2000  compliance as a  jurisdictional
  
                                         22
  utility  having all  mission-critical  Year 2000  hardware and software  updates
  and/or replacements  installed and tested on or before March 31, 1999. On August
  6, 1998,  the Company filed its written  response,  in which the Company  stated
  that with a few carefully-assessed and closely-managed  exceptions,  the Company
  will have all mission-critical systems Year 2000 ready by June 1999. Pursuant to
  the  formal  investigation  on  Year  2000  compliance,  the  Company  presented
  testimony before the PUC on November 20, 1998.
  
           On February 19, 1999, the PUC issued a Secretarial Letter notifying the
  Company that it had hired a consultant  to perform an  assessment of the Company
  and thirteen other  utilities to evaluate the accuracy of their responses to the
  compliance  program questions and testimony provided before the PUC. The Company
  complied  with the PUC's  directive  in the  Secretarial  Letter to file updated
  written responses to compliance questions by March 8, 1999, and to meet with the
  consultant  during a one-day  on-site  review session on March 8, 1999. On March
  31,  1999,   the  Company  filed   contingency   plans  with  the  PUC  for  its
  mission-critical  systems  scheduled  to be  ready  after  the  March  31,  1999
  deadline.
  
           On April 8,  1999,  the PUC  issued an order  requiring  the  Office of
  Administrative  Law Judge to identify (i) utilities which have complied with the
  PUC's order of July 17, 1998 (the Order); (ii) utilities which have demonstrated
  good cause for an extension of time within which they will fully comply with the
  Order; and (iii) those utilities which have not complied with the Order and have
  not shown good cause for an extension. The PUC required that this information be
  posted to the PUC internet  website and  periodically  updated.  The PUC further
  ordered that the  Investigation  with respect to utilities who have demonstrated
  good cause for an  extension of time remain open and under the  jurisdiction  of
  the  Office  of  Administrative  Law  Judge  until  compliance  is  achieved  or
  enforcement  is  warranted.  PECO  Energy  has been  identified  by the PUC as a
  utility which has demonstrated  good cause for an extension of time within which
  it  will  fully  comply  with  the  Order.  Additional  reporting  dates  to the
  Administrative Law Judge include July 1, 1999 and October 1, 1999.
  
           On May 11, 1998, the NRC issued a generic letter  requiring all nuclear
  plant operators to provide the NRC with the following information concerning the
  operators' programs,  planned or implemented,  to address Year 2000 computer and
  system issues at its facilities:  (1) submission of a written response within 90
  days,  indicating  whether the  operator  has pursued  and  continues  to pursue
  implementation  of Year  2000  programs  and  addressing  the  program's  scope,
  assessment process,  plans for corrective  actions,  quality assurance measures,
  contingency  plans and  regulatory  compliance,  and (2) submission of a written
  response,  no later than July 1, 1999,  confirming that such facilities are Year
  2000  ready,  or will be Year  2000  ready,  by the year  2000  with  regard  to
  compliance with the terms and conditions of the license(s) and NRC  regulations.
  On July 30,  1998,  the  Company  filed its  90-day  required  written  response
  indicating  that the Company has pursued and is continuing to pursue a Year 2000
  program  which  is  similar  to that  outlined  in  Nuclear  Utility  Year  2000
  Readiness, NEI/NUSMG 97.07.
  
           From November 3 to November 5, 1998, members of the NRC staff conducted
  an audit of the Company's Year 2000 Program for the Limerick Generating Station,
  Units No. 1 and No. 2. Some of the  observations  of the audit team  included in
  their written  report  issued on December 18, 1998,  were that (1) the Company's
  readiness  program  is  comprehensive  and based on the  guidance  contained  in
  
                                         23
  NEI/NUSMG  97.07,  (2) the program is receiving  proper  management  support and
  oversight, and (3) project schedules are being aggressively pursued.
  
           On April 28, 1999,  the NRC issued  Information  Notice 99-12  advising
  nuclear power plant licensees that NRC staff would be conducting additional Year
  2000 readiness and contingency planning  site-specific reviews at all commercial
  nuclear power plants. The NRC performed its site-specific review of Peach Bottom
  from May 24 to May 28, 1999,  and its review of Limerick from June 7 to June 10,
  1999.
  
           On June 30, 1999,  PECO Energy filed its completed  response to Generic
  Letter 98-01. In the response,  PECO Energy confirmed that with the exception of
  five  non-safety  plant  systems,  its Peach  Bottom  Atomic  Power  Station and
  Limerick  Generating  Stations are Year 2000 ready.  The Company advised the NRC
  that remediation for three of the remaining  systems is scheduled for completion
  by September 30, 1999, and remediation for the other two systems is scheduled to
  occur during planned plant outages in September 1999.
  
           For additional information regarding the Year 2000 Readiness Disclosure
  see "Management's  Discussion and Analysis of Financial Condition and Results of
  Operations" in the Company's Annual Report to Shareholders for the year 1998.
  
  FORWARD-LOOKING STATEMENTS
           Except for the historical  information contained herein, certain of the
  matters discussed in this Report are forward-looking  statements,  including the
  estimated  earnings per share benefits of the application of the Transition Bond
  proceeds  for  1999  and  2000,  and  accordingly,  are  subject  to  risks  and
  uncertainties.  The factors that could cause actual results to differ materially
  include  those  discussed  herein as well as those listed in notes 2, 8 and 9 of
  Notes to Condensed Consolidated Financial Statements and other factors discussed
  in the Company's  filings with the SEC. Readers are cautioned not to place undue
  reliance on these forward-looking statements, which speak only as of the date of
  this  Report.  The Company  undertakes  no  obligation  to publicly  release any
  revision to these forward-looking  statements to reflect events or circumstances
  after the date of this Report.
  
  ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
  
           The Company has entered  into  interest  rate swaps to manage  interest
  rate  exposure  associated  with the  issuance  of two  floating  rate series of
  Transition  Bonds. At June 30, 1999, the fair value of these instruments was $52
  million based on the present value difference between the contracted rate (i.e.,
  hedged rate) and the market rates at that date.  A  hypothetical  50 basis point
  increase or  decrease in the spot yield at June 30, 1999 would have  resulted in
  an aggregate  fair value of these  interest rate swaps of $91.2 million or $10.7
  million, respectively. If the derivative instruments had been terminated at June
  30, 1999,  these  estimated  fair values  represent the amount to be paid by the
  counterparties to the Company.
  
                                         24
  The Company's growing market share in the retail and wholesale electric
  marketplace  increases the Company's reliance on the efficient  operation of its
  generating  units.  The  Company's  ability  to  fully  capitalize  on  volatile
  wholesale  market prices is also  dependent on the  performance of the Company's
  generating units.
  
                                         25
  PART II - OTHER INFORMATION
  
  ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
  
           Information  regarding the  submission of matters to a vote of security
  holders is presented in the March 31, 1999 Form 10-Q.
  
  ITEM 5.  OTHER INFORMATION
  
           As  previously  reported  in the  1998  Form  10-K,  the NRC  issued  a
  confirmatory  order  modifying  the  license  for  Limerick  Generating  Station
  (Limerick)  Units No. 1 and No. 2  requiring  that the  Company  complete  final
  implementation  of corrective  actions on the Thermo-Lag 330 issue by completion
  of the April 1999  refueling  outage of Limerick Unit No. 2. By letter dated May
  3, 1999,  the NRC approved the  Company's  request to extend the  completion  of
  Thermo-lag corrective actions at Limerick until September 30, 1999.
  
           As previously  reported in the 1998 Form 10-K, in October 1990, General
  Electric  Company (GE) reported that crack  indications were discovered near the
  seam welds of the core  shroud  assembly  in a GE Boiling  Water  Reactor  (BWR)
  located outside the United States.  As a result,  GE issued a letter  requesting
  that the owners of GE BWRs take interim corrective  actions,  including a review
  of fabrication  records and visual  examinations of accessible areas of the core
  shroud seam welds.  Each of the  reactors at Limerick  and Peach  Bottom is a GE
  BWR. In accordance with industry experience and guidance, initial examination of
  Limerick  Unit No. 2 was  completed  during  the April  1999  refueling  outage.
  Although crack  indications were identified,  the results of the inspections and
  evaluations  conclude that the condition of the Limerick Unit No. 2 core shroud,
  projected  through at least the next operating cycle,  will support the required
  safety  margins,   specified  in  the  ASME  code  and  reinforced  by  industry
  recommendations.
  
          As  previously  reported  in the 1998 Form 10-K,  as a result of several
  BWRs  experiencing  clogging  of some  emergency  core  cooling  system  suction
  strainers,  which are part of the water supply system for  emergency  cooling of
  the reactor  core,  the NRC issued a Bulletin in May 1996 to  operators  of BWRs
  requesting  that measures be taken to minimize the  potential for clogging.  The
  NRC proposed  three  resolution  options,  including the  installation  of large
  capacity passive strainers,  with a request that actions be completed by the end
  of the  unit's  first  refueling  outage  after  January  1997.  Strainers  were
  installed at Peach Bottom Unit No. 3 during the October 1997  refueling  outage.
  Strainers  were  installed at Peach  Bottom Unit No. 2 and  Limerick  Unit No. 1
  during their  refueling  outages in October  1998 and April 1998,  respectively.
  Strainers  were installed at Limerick Unit No. 2 during the April 1999 refueling
  outage. The Company cannot predict what other actions,  if any, the NRC may take
  in this matter.
  
            On June 22, 1999,  Pennsylvania Governor Tom Ridge signed into law the
  Natural Gas Choice and  Competition  Act  ("Act")  which  expands  choice of gas
  suppliers to residential and small commercial  customers and eliminates the five
  percent gross receipts tax on gas  distribution  companies'  sales of gas. Large
  commercial  and industrial  customers  have been able to choose their  suppliers
  since 1984.  Currently,  approximately  one-third of the Company's  total yearly
  throughput is supplied by third parties.
  
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  The  Act  permits  gas  distribution  companies  to  continue  to  make
  regulated  sales of gas to their  customers.  The Act  does not  deregulate  the
  transportation  service  provided by gas  distribution  companies  which remains
  subject to rate regulation.  Gas distribution companies will continue to provide
  billing, metering, installation, maintenance and emergency response services.
  
           In  compliance  with  the  schedule   ordered  by  the  Public  Utility
  Commission  ("PUC"),  the  Company  must file with the PUC by December 2, 1999 a
  restructuring  plan for the  implementation  of gas  deregulation  and  customer
  choice of gas service suppliers in its service territory  (Restructuring  Plan).
  The  Company  expects gas to flow on its system  pursuant to customer  choice on
  July 1, 2000.  The Company is currently  analyzing  the impact of the Act on its
  operations. The Company believes the impact on the Company would not be material
  because of the PUC's existing requirement that gas distribution companies cannot
  collect  more  than  the  actual  cost of gas  from  customers,  and  the  Act's
  requirement that suppliers must accept assignment or release, at contract rates,
  the portion of the gas distribution company's firm interstate pipeline contracts
  required to serve the suppliers' customers.
  
  ITEM 6.  EXHIBITS AND REPORTS ON FORM 8-K
  (a)      Exhibits:
  
           27 - Financial Data Schedule.
  
  (b)      Reports on Form 8-K filed during the reporting period:
  
           Report,  dated  April 15,  1999  reporting  information  under "ITEM 5.
                    OTHER EVENTS" regarding AmerGen Energy Company, LLC, the joint
                    venture between the Company and British Energy,  Inc., signing
                    an interim  agreement  to purchase the Clinton  Nuclear  Power
                    Station from  Illinois  Power (IP),  a subsidiary  of Illinova
                    Corporation.
  
           Report,  dated June 24, 1999 reporting information under "ITEM 5. OTHER
                    EVENTS" regarding AmerGen's signing a definitive  agreement to
                    purchase  the  Nine  Mile  Point  Unit  1  Nuclear  Generating
                    Facility  from Niagara  Mohawk  Power  Corporation  (NIMO),  a
                    subsidiary of Niagara Mohawk  Holdings,  Inc. AmerGen has also
                    entered  into an agreement  to purchase  NIMO's 41%  ownership
                    interest in Nine Mile Point Unit 2 Nuclear Generating Facility
                    (NMP-2) and New York State  Electric  and Gas Corp.'s  (NYSEG)
                    18% interest in NMP-2.  NYSEG is a wholly owned  subsidiary of
                    Energy East, Inc.
  
           Reports on Form 8-K filed subsequent to the reporting period:
  
           Report,  dated July 1, 1999 reporting  information under "ITEM 5. OTHER
                    EVENTS"   regarding   AmerGen's  signing  a  definitive  asset
                    purchase agreement to purchase Clinton.
  
                                         27
  Signatures
  
           Pursuant to  requirements  of the Securities  Exchange Act of 1934, the
  registrant  has duly  caused  this  report  to be  signed  on its  behalf by the
  undersigned thereunto duly authorized.
  
                                 PECO ENERGY COMPANY
  
                                 /s/ Michael J. Egan
                                 MICHAEL J. EGAN
                                 Vice President and
                                 Senior Vice President and
                                 Chief Financial Officer
                                 (Chief Accounting Officer)
  
  Date:  August 13, 1999
  
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