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 March 31, 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 191,812,306 shares of common stock outstanding on May 7, 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)
  
  <TABLE>
  <CAPTION>
                                                            Three Months Ended
                                                                 March 31,
                                                        --------------------------
                                                            1999           1998
                                                        -----------    -----------
  <S>                                                   <C>            <C>        
  OPERATING REVENUES
       Electric                                         $   1,038.9    $   1,003.0
       Gas                                                    217.5          187.2
                                                        -----------    -----------
       TOTAL OPERATING REVENUES                             1,256.4        1,190.2
                                                        -----------    -----------
  OPERATING EXPENSES
       Fuel and Energy Interchange                            465.1          383.0
       Operating and Maintenance                              288.7          283.2
       Depreciation and Amortization                           56.3          154.7
       Taxes Other Than Income Taxes                           75.3           82.1
                                                        -----------    -----------
       TOTAL OPERATING EXPENSES                               885.4          903.0
                                                        -----------    -----------
  OPERATING INCOME                                            371.0          287.2
                                                        -----------    -----------
  OTHER INCOME AND DEDUCTIONS
       Interest Expense                                       (74.3)         (85.0)
       Company Obligated Mandatorily Redeemable
         Preferred Securities of a Partnership                 (7.4)          (7.7)
       Allowance for Funds Used During Construction             0.4            0.6
       Other, Net                                             (42.0)         (12.8)
                                                        -----------    -----------
       TOTAL OTHER INCOME AND DEDUCTIONS                     (123.3)        (104.9)
                                                        -----------    -----------
  INCOME BEFORE INCOME TAXES                                  247.7          182.3
  
  INCOME TAXES                                                 98.0           68.7
                                                        -----------    -----------
  NET INCOME                                                  149.7          113.6
  
  PREFERRED STOCK DIVIDENDS                                     3.3            3.3
                                                        -----------    -----------
  EARNINGS APPLICABLE TO COMMON STOCK                   $     146.4    $     110.3
                                                        ===========    ===========
  
  
  AVERAGE SHARES OF COMMON STOCK
       OUTSTANDING  (Millions)                                223.4          222.5
                                                        ===========    ===========
  
  BASIC EARNINGS PER AVERAGE
  COMMON SHARE (Dollars)                                $      0.66    $      0.50
                                                        ===========    ===========
  
  DILUTIVE EARNINGS PER AVERAGE
  COMMON SHARE (Dollars)                                $      0.65    $      0.50
                                                        ===========    ===========
  
  
  DIVIDENDS PER AVERAGE COMMON SHARE (Dollars)          $      0.25    $      0.25
                                                        ===========    ===========
  
  
  BOOK VALUE PER COMMON SHARE (Dollars)                 $     12.18    $     12.49
                                                        ===========    ===========
  </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>
                                                          March 31,    December 31,
                                                            1999          1998
                                                         -----------   -----------
                                                         (Unaudited)
  <S>                                                    <C>           <C>        
  ASSETS
  
  UTILITY PLANT
  Electric - Transmission & Distribution                 $   3,870.8   $   3,833.8
  Electric - Generation                                      1,722.0       1,713.4
  Gas                                                        1,138.2       1,132.0
  Common                                                       408.7         407.3
                                                         -----------   -----------
  
                                                             7,139.7       7,086.5
  Less Accumulated Provision for Depreciation                2,950.7       2,891.3
                                                         -----------   -----------
  
                                                             4,189.0       4,195.2
  Nuclear Fuel, net                                            128.0         141.9
  Construction Work in Progress                                290.1         272.6
  Leased Property, net                                         138.3         154.3
                                                         -----------   -----------
  
                                                             4,745.4       4,764.0
                                                         -----------   -----------
  
  
  CURRENT ASSETS
  Cash and Temporary Cash Investments                        2,702.8          48.1
  Accounts Receivable, net
       Customer                                                183.0          97.5
       Other                                                   262.5         213.2
  Inventories, at average cost
       Fossil Fuel                                              84.9          92.3
       Materials and Supplies                                   83.1          82.1
  Deferred Energy Costs - Gas                                    0.8          29.9
  Other                                                        188.7          19.0
                                                         -----------   -----------
  
                                                             3,505.8         582.1
                                                         -----------   -----------
  
  DEFERRED DEBITS AND OTHER ASSETS
  Competitive Transition Charge                              5,274.6       5,274.6
  Recoverable Deferred Income Taxes                            613.9         614.4
  Deferred Non-Pension Postretirement Benefits Costs            89.3          90.9
  Investments                                                  534.0         538.1
  Loss on Reacquired Debt                                       75.6          77.2
  Other                                                        132.7         107.1
                                                         -----------   -----------
  
                                                             6,720.1       6,702.3
                                                         -----------   -----------
  
  TOTAL                                                  $  14,971.3   $  12,048.4
                                                         ===========   ===========
  </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>
                                                      March 31,      December 31,
                                                        1999            1998
                                                     -----------    -----------
                                                     (Unaudited)
  <S>                                                <C>            <C>        
  CAPITALIZATION AND LIABILITIES
  
  CAPITALIZATION
  Common Shareholders' Equity
       Common Stock (No Par)                         $   3,602.6    $   3,589.0
       Other Paid-In Capital                                 1.2            1.2
       Accumulated Deficit                                (429.3)        (532.9)
       Treasury Stock                                     (695.9)            --
  Preferred and Preference Stock
       Without Mandatory Redemption                        137.5          137.5
       With Mandatory Redemption                            92.7           92.7
  Company Obligated Mandatorily Redeemable
       Preferred Securities of a Partnership               349.4          349.4
  Long-Term Debt                                         6,084.0        2,919.6
                                                     -----------    -----------
  
                                                         9,142.2        6,556.5
                                                     -----------    -----------
  
  CURRENT LIABILITIES
  Notes Payable, Bank                                       68.0          525.0
  Long-Term Debt Due Within One Year                       939.4          361.5
  Capital Lease Obligations Due Within One Year             68.8           69.0
  Accounts Payable                                         276.9          316.2
  Taxes Accrued                                            342.0          170.5
  Interest Accrued                                          67.1           61.5
  Deferred Income Taxes                                      4.0           14.1
  Other                                                    236.6          217.4
                                                     -----------    -----------
  
                                                         2,002.8        1,735.2
                                                     -----------    -----------
  
  DEFERRED CREDITS AND OTHER LIABILITIES
  Capital Lease Obligations                                 69.5           85.3
  Deferred Income Taxes                                  2,362.5        2,376.9
  Unamortized Investment Tax Credits                       296.4          300.0
  Pension Obligation                                       219.3          219.3
  Non-Pension Postretirement Benefits Obligation           428.6          421.1
  Other                                                    450.0          354.1
                                                     -----------    -----------
  
                                                         3,826.3        3,756.7
                                                     -----------    -----------
  
  COMMITMENTS AND CONTINGENCIES (NOTE 6)
  
  TOTAL                                              $  14,971.3    $  12,048.4
                                                     ===========    ===========
  </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>
                                                                    Three Months Ended
                                                                        March 31,
                                                                ----------------------
                                                                    1999         1998
                                                                ----------    --------
  <S>                                                           <C>           <C>     
  CASH FLOWS FROM OPERATING ACTIVITIES
  
  NET INCOME                                                    $    149.7    $  113.6
  Adjustments to Reconcile Net Income to Net Cash
       Provided by Operating Activities:
  Depreciation and Amortization                                       73.9       170.9
  Deferred Income Taxes                                              (23.0)       (6.8)
  Amortization of Investment Tax Credits                              (3.6)       (4.5)
  Deferred Energy Costs                                               29.0        19.0
  Changes in Working Capital:
       Accounts Receivable                                          (134.7)       24.9
       Inventories                                                     6.4        17.7
       Accounts Payable                                              (39.3)      (74.4)
       Other Current Assets and Liabilities                           35.6       (45.5)
  Other Items Affecting Operations                                    88.4        16.2
                                                                ----------    --------
  
  
  CASH FLOWS PROVIDED BY OPERATING ACTIVITIES                        182.4       231.1
                                                                ----------    --------
  
  
  CASH FLOWS FROM INVESTING ACTIVITIES
  
  Investment in Plant                                                (76.9)     (116.5)
  Increase in Investments                                             (5.3)      (11.1)
                                                                ----------    --------
  
  
  
  NET CASH FLOWS USED IN INVESTING ACTIVITIES                        (82.2)     (127.6)
                                                                ----------    --------
  
  
  
  CASH FLOWS FROM FINANCING ACTIVITIES
  
  Change in Short-Term Debt                                         (457.0)      (17.0)
  Issuance of Long-Term Debt                                       4,009.6        (5.5)
  Retirement of Long-Term Debt                                      (263.0)         --
  Common Stock Repurchase                                           (695.9)         --
  Loss on Reacquired Debt                                              1.6         1.8
  Dividends on Preferred and Common Stock                            (59.5)      (58.9)
  Other Items Affecting Financing                                     18.7        (2.3)
                                                                ----------    --------
  
  
  NET CASH FLOWS PROVIDED BY (USED IN) FINANCING ACTIVITIES        2,554.5       (81.9)
                                                                ----------    --------
  
  
  INCREASE IN CASH AND CASH EQUIVALENTS                            2,654.7        21.6
                                                                ----------    --------
  
  
  CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD                    48.1        33.4
                                                                ----------    --------
  
  
  CASH AND CASH EQUIVALENTS AT END OF PERIOD                    $  2,702.8    $   55.0
                                                                ==========    ========
  </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 March
  31,  1999 and for the three  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 (1998
  Form 10-K).
  
  
  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
  <FN>
       (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 March 31,
       1999.
  </FN>
  </TABLE>
  
                                         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  will be  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.  The fair value of $5 million was based on the present  value  difference
  between the  contracted  rate (i.e.,  hedged rate) and the market rates at March
  31, 1999.
  
       The  aggregate  change  in fair  value of the  Transition  Bond  derivative
  instruments that would have resulted from a hypothetical 50 basis point decrease
  in the spot yield at March 31, 1999 is  estimated  to be $38.2  million.  If the
  derivative  instruments  had been  terminated at March 31, 1999,  this estimated
  fair  value   represents   the  amount  to  be  paid  by  the   Company  to  the
  counterparties.
  
       The aggregate  change in fair value of these  derivative  instruments  that
  would have  resulted  from a  hypothetical  50 basis point  increase in the spot
  yield at March 31, 1999 is  estimated  to be $45.9  million.  If the  derivative
  instruments  had been  terminated at March 31, 1999,  this  estimated fair value
  represents 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 $3.9 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.  On March 26, 1999, the Company
  settled the forward purchase  agreements  relating to its Common Stock resulting
  in the  purchase by the Company of 21.5  million  shares of Common  Stock for an
  aggregate purchase price of $696 million. In addition, the Company repaid a $400
  million term loan,  $208 million of  commercial  paper,  $48 million of accounts
  receivable  financing and paid $21 million of debt issuance costs. The remaining
  proceeds of $2.6 billion are  included in cash at March 31,  1999.  On March 26,
  1999, the Company called for redemption four series of its First Mortgage Bonds,
  7.75% Series due 2023,  7.25% Series due 2024,  7.125% Series due 2023 and 7.75%
  Series 2 due 2023, totaling $775 million.
  
  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.
  
                                         7
  
  <PAGE>
  
       During the first quarter of 1999, the Company completed the redesign of its
  internal  reporting  structure to separate  its  distribution,  generation,  and
  ventures  operations  into business units and provide  financial and operational
  data on the same basis to senior management. The Company's distribution business
  unit 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 generating 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.
  
       The  Company's  segment  information  as of and for the three  months ended
  March 31, 1999 as compared to the same 1998 period is as follows (in millions of
  dollars):
  <TABLE>
  <CAPTION>
                                                                                               Intersegment
                        Distribution         Generation        Ventures         Corporate        Revenues       Consolidated
                        ------------         ----------        --------         ---------        --------       ------------
  <S>                   <C>                 <C>               <C>              <C>            <C>              <C>     
  Revenues:
      1999                 $910.1              $443.9            $103.8           $ -            $(201.4)         $1,256.4
      1998                 $949.5              $465.0            $ 17.0           $ -            $(241.3)         $1,190.2
  EBIT (a):
      1999                 $354.7              $ 46.5(b)        $( 30.6)(c)       $(41.6)                         $  329.0
      1998                 $307.3              $ 41.4           $( 27.5)          $(46.8)                         $  274.4
  Total Assets:                                                                  
      1999              $12,366.3(d)         $1,919.5            $246.7           $438.8                         $14,971.3
      1998              $ 9,759.2            $1,686.8            $216.9           $385.5                         $12,048.4
  <FN>
  (a)  EBIT - Earnings Before Interest and Income Taxes.
  (b)  Includes an $11.8 million reserve related to the Grays Ferry power purchase
       agreement.
  (c)  Includes $14.6 million  related to the write-off of the investment in Grays
       Ferry in connection with the settlement of litigation.
  (d)  Includes $2.6 billion of proceeds from securitization of stranded costs.
  </FN>
  </TABLE>
  
  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:
  
                                         8
  
  <PAGE>
                                              Three Months Ended
                                                   March 31,
                                              ------------------
                                               1999         1998
                                             -------      -------
                                              (Millions of shares)
  
  Average Common Shares Outstanding            223.4        222.5
  
  Assumed Conversion of Stock Options            1.3           -- 
                                             -------      -------
  
  Potential Average Dilutive
    Common Shares Outstanding                  224.7        222.5
                                             =======      =======
  
  
  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 $353 million of designated  accounts  receivable  until
  November 2000. At March 31, 1999,  the Company had sold a $353 million  interest
  in  accounts  receivable,  consisting  of a $289  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 $64 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 $353 million
  interest,  which,  if not met,  requires the Company to deposit cash in order to
  satisfy  such   requirements.   The  Company,   at  March  31,  1999,  met  such
  requirements.  At March  31,  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 5.05%.
  
  
  6.   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 March 31, 1999, the Company had entered into long-term  agreements  with
  unaffiliated   utilities  to  purchase   transmission   rights.  These  purchase
  commitments  result in  obligations  of  approximately  $47 million in 1999, $88
  million in 2000,  $22 million in 2001,  and $10 million per year in 2002 through
  2005.
  
       The Company has  identified  28 sites where former  manufactured  gas plant
  (MGP) activities have or may have resulted in actual site  contamination.  As of
  March  31,  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
  results in a restructuring of the power purchase  agreement  between the Company
  and Grays Ferry.  The settlement also provides for the transfer of the Company's
  interest  in  the  partnership  to the  partnership.  Accordingly,  the  
  
                                         9
  
  <PAGE>
  
  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 three months  ended March 31, 1999.  The  settlement
  also resolves the litigation with  Westinghouse  Power  Generation and The Chase
  Manhattan Bank.
  
  7.   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.  The new standard will be effective for fiscal years beginning after
  June 15, 1999. The Company expects to adopt SFAS No. 133 in the first quarter of
  2000.  The Company is in the process of evaluating the impact of SFAS No. 133 on
  its financial statements.
  
       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.
  
       At March 31,  1999,  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 not subject to EITF 98-10 or mark-to-market accounting.
  
                                         10
  <PAGE>
       The Company  records  revenues  and  expenses  with the energy  commitments
  consistent with when the underlying physical  transaction closes.  Additionally,
  the Company  evaluates its energy  commitments for impairment based on the lower
  of cost or market.  At March 31,  1998,  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.  During  1999,  two-thirds  of each class of the  Company's
  retail electric customers in its traditional service territory will 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  March  31,  1999
  approximately 13% of the Company's  residential  customers, approximately 22% of
  its commercial  customers and approximately 56% 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   138,000  business  and  residential   customers   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.
  
       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.
  
       During the first quarter of 1999, the Company completed the redesign of its
  internal  reporting  structure to separate  its  distribution,  generation,  and
  ventures  operations  into business units and provide  financial and operational
  data on the same basis to senior management. The Company's distribution business
  unit 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 generating 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.
  
  
  RESULTS OF OPERATIONS
  
       The  Company's  Statements  of Income for the three  months ended March 31,
  1998 reflect the reclassification of the results of operations of Exelon Energy,
  from Other Income and Deductions.
  
                                         12
  <PAGE>
  
  Revenue and Expense Items as a
  Percentage of Total Operating
  Revenues                                               Percentage Dollar Changes
        1999     1998                                            1999-1998
        ----     ----                                            ---------
  
         83%      84%           Electric                            4%
         17%      16%           Gas                                16%
       ----     ---- 
        100%     100%           Total Operating Revenues            6%
       ----     ---- 
  
         37%      32%           Fuel and Energy Interchange        21%
         23%      24%           Operating and Maintenance          (2%)
          4%      13%           Depreciation and Amortization     (62%)
          6%       7%           Taxes Other Than Income            (8%)
       ----     ---- 
         70%      76%           Total Operating Expenses           (2%)
       ----     ---- 
  
         30%      24%           Operating Income                   30%
       ----     ---- 
  
         (7%)     (8%)          Interest Expense                  (12%)
         (3%)     (1%)          Other Income and Deductions      (241%)
       ----     ---- 
         20%      15%           Income Before Income Taxes         36%
          8%       6%           Income Taxes                       43%
       ----     ---- 
         12%       9%           Net Income                         32%
       ----     ---- 
  
  Operating Revenues
       Electric revenues increased $36 million,  or 4%, for the three months ended
  March 31, 1999 compared to the same 1998 period.  The increase was  attributable
  to higher  revenues  from the  ventures  business  unit of $88  million  and the
  generation  business unit of $19 million,  partially offset by lower revenues at
  the  distribution  business unit of $71 million.  The increase from the ventures
  business unit was primarily from increased volume in Pennsylvania resulting from
  the  commencement  of the sale of competitive  electric  generation  services by
  Exelon Energy.  The increase from the generation  business unit was attributable
  to the marketing of excess generation  capacity as a result of lower native load
  requirements  as a result of  competition.  The decrease  from the  distribution
  business  unit was  attributable  to $68  million  as a result  of lower  volume
  associated  with the effects of  competition  and $56 million  related to the 8%
  across-the-board rate reduction mandated by the Final Restructuring Order. These
  decreases were partially offset by $36 million of PJM  Interconnection LLC (PJM)
  network  transmission  service  revenue  which  commenced  April 1, 1998 and $17
  million  related to  increased  sales  volume  from colder  weather  conditions.
  Stranded  cost  recovery is  included in the  Company's  retail  electric  rates
  beginning January 1, 1999.
  
       Gas  revenues  increased  $30  million,  or 16%, for the three months ended
  March 31, 1999  compared to the same 1998 period.  The  increase  was  primarily
  attributable to increased volume as a result of colder weather conditions of $20
  million and increased volume from new customers of $10 million.
  
                                         13
  
  <PAGE>
  
  Fuel and Energy Interchange Expense
       Fuel and energy interchange  expense increased $82 million, or 21%, for the
  three  months  ended  March 31,  1999  compared  to the same 1998  period.  As a
  percentage of revenue, fuel and interchange expenses were 37% as compared to 32%
  in the comparable prior year period. These increases were attributable to higher
  fuel and energy  interchange  expenses  from the ventures  business  unit of $69
  million and the distribution  business unit of $63 million,  partially offset by
  lower fuel and energy  interchange  expenses  of $50  million at the  generation
  business unit.  The increase from the ventures  business unit was primarily from
  increased  volume  related  to  Exelon  Energy  sales.  The  increase  from  the
  distribution  business  unit was  primarily  attributable  to $27 million of PJM
  network  transmission service fees which commenced April 1, 1998, $26 million of
  purchases in the spot market and $10 million of  additional  gas  purchases as a
  result of higher volume  associated with colder  weather.  The decrease from the
  generation business unit was primarily attributable to $78 million of lower fuel
  purchases  as a  result  of  the  effects  of  competition  experienced  by  the
  distribution  business unit. This increase was partially offset by a $12 million
  reserve related to the Grays Ferry power purchase  agreement and fuel savings of
  $16  million  from 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
       Operating and maintenance expense increased $6 million, or 2% for the three
  months ended March 31, 1999  compared to the same 1998 period.  The increase was
  primarily  attributable to increased information  technology expenses related to
  Year 2000  remediation of $12 million  partially offset by lower expenses at the
  generation business unit of $8 million as a result of the full return to service
  of Salem in April 1998.  As a percentage of revenue,  operating and  maintenance
  expenses were 23% as compared to 24% in the comparable prior year period.
  
  Depreciation and Amortization Expense
       Depreciation and amortization  expense  decreased $98 million,  or 64%, for
  the three  months ended March 31, 1999  compared to the same 1998  period.  As a
  percentage of revenue,  depreciation and amortization expense was 4% 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  established a regulatory  asset,
  Deferred  Generation Costs  Recoverable in Current Rates of $424 million,  which
  was fully  amortized in 1998, and 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 $7 million,  or 8%, for the three months
  ended  March 31, 1999  compared  to the same 1998  period.  As a  percentage  of
  revenue,  taxes other than income were 6%, as compared to 7%, in the  comparable
  prior year period.  The decrease was attributable to lower gross receipts tax of
  $3 million and lower capital stock tax of $4 million.
  
                                         14
  <PAGE>
  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
  decreased  $11  million,  or 12%,  for the three  months  ended  March 31,  1999
  compared to the same 1998 period.  As a percentage of revenue,  interest charges
  were 7% as compared to 8% in the  comparable  prior year period.  The  Company's
  ongoing program to reduce and/or refinance  higher cost,  long-term debt reduced
  interest charges by $16 million.  This decrease was partially offset by interest
  on the Transition Bonds of $5 million.
  
  Other Income and Deductions
       Other income and deductions  excluding  interest  charges was a loss of $42
  million for the three  months  ended March 31, 1999 as compared to a loss of $13
  million in the same 1998  period.  The  decrease of $29  million  was  primarily
  attributable  to the  write-off of the  investment  in Grays Ferry in connection
  with  the  settlement  of  litigation  of $15  million,  the  abandonment  of an
  information  system of $7 million and additional losses from equity  investments
  in  telecommunications  ventures and non-utility  operations of $7 million. As a
  percentage of revenue,  other income and deductions were 3% as compared to 1% in
  the comparable prior year period.
  
  Income Taxes
       The effective  tax rate was  proportionate  to the  statutory  rate for the
  three  months  ended March 31, 1999 as compared to 38% in the same 1998  period.
  The  effective  tax  rate  for  the  three  months  ended  March  31,  1998  was
  disproportionate  to the statutory rate as a result of the full normalization of
  deferred taxes associated with deregulated  generation plant and amortization of
  investment tax credits.
  
  Preferred Stock Dividends
       Preferred  stock  dividends  for the three months ended March 31, 1999 were
  consistent with the same 1998 period.
  
  
  DISCUSSION OF LIQUIDITY AND CAPITAL RESOURCES
       Cash flows provided by operating  activities  decreased $49 million to $182
  million for the three months ended March 31, 1999 as compared to $231 million in
  the same 1998  period.  The  decrease was  primarily  attributable  to less cash
  generated  by  operations  of $66  million,  changes in  working  capital of $55
  million  principally  related to the  timing of gross  receipts  tax,  partially
  offset  by  other  items  affecting  operations  of  $72  million,   principally
  consisting  of the  deferred  gain  on the  unwinding  of  interest  rate  swaps
  associated with the issuance of Transition Bonds.
  
       Cash flows used by  investing  activities  were $82  million  for the three
  months ended March 31, 1999 as compared to $128 million in the  comparable  1998
  period.  Expenditures under the Company's  construction program decreased to $77
  million in the current period.
  
                                         15
  <PAGE>
  
       Cash flows provided by financing activities were $2,555 million as compared
  to cash used in financing activities of $82 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  $720 million and the  settlement  of the Company's
  common stock forward purchase contract for $696 million.
  
       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 from  variable  distribution  charges  (both of  which  are  usage-based
  charges).
  
       PETT used the $3.99 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%.
  Concurrently  with the issuance of the  Transition  Bonds,  the Company repaid a
  $400 million  term loan,  $208  million of  commercial  paper and $48 million of
  accounts  receivable  financing  and  repurchased  21.5  shares of common  stock
  pursuant to forward  repurchase  arrangements for an aggregate purchase price of
  $696 million.  The Company also called for redemption $ 775 million of its First
  Mortgage  Bonds as follows:  7.75%  Series due 2023,  7.25%  Series due 2024 and
  7.125%  Series due 2023 on April 26, 1999 and 7.75%  Series 2 due 2023 on May 3,
  1999.  The Company  also plans to call for  redemption  its COMRPS 9% Series due
  2043 on August 1, 1999. The Company currently  anticipates that it will complete
  the repurchase of common equity through open market  purchases from time to time
  in compliance  with  Securities  and Exchange  Commission  rules.  The number of
  shares  purchased  and the timing and manner or  purchases  are  dependent  upon
  market conditions.
  
       Although the Company has sold the ITP to PETT, the ITC revenue,  as well as
  all interest  expense and  amortization  expense  associated with the Transition
  Bonds, will be reflected on the Company's  Consolidated Statement of Income. The
  combined  schedule  for  amortization  of the  CTC  and  ITC  assets  will be 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  proposed
  capital reduction by the Company, the Company expects its debt-to-total  capital
  ratio to be 60% upon  completion  of the  application  of the proceeds  from the
  securitization.  The  Company  currently  projects  that  it will  complete  the
  majority of the targeted  debt and  preferred  security  reductions by August 1,
  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 additional expense, combined with the anticipated
  
                                         16
  <PAGE>
  
  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.
  
       At March 31,  1999,  the  Company  had  outstanding  $68  million  of notes
  payable, all of which were commercial paper. In addition, at March 31, 1999, the
  Company had formal and informal lines of bank credit  aggregating  $100 million.
  At March 31, 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
       Due to the  severity  of the  potential  impact of the Year 2000 Issue (Y2K
  Issue) on the electric utility industry, the Company has adopted a comprehensive
  schedule to achieve Y2K readiness by the time  specified by the NRC. The Company
  has dedicated  extensive resources to its Y2K Project (Project) and believes the
  Project  is  progressing  on  schedule.  The  Project  is  addressing  the issue
  resulting from computer programs using two digits rather than four to define the
  applicable   year  and  other   programming   techniques   that  constrain  date
  calculations or assign special  meanings to certain dates.  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.
  
       The Company has determined  that it will be 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 is
  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 Project is divided into four major  sections -  Information  Technology
  Systems (IT Systems),  Embedded Technology (devices used to control,  monitor or
  assist  the   operation  of  equipment,   machinery  or  plant),   Supply  Chain
  (third-party  suppliers and customers),  and Contingency  Planning.  The general
  phases common to all sections  are: (1)  inventorying  Y2K items;  (2) assigning
  priorities  to  identified  items;  (3)  assessing  the Y2K  readiness  of items
  
                                         17
  
  <PAGE>
  
  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 226
  are IT Systems. The current readiness status of IT Systems is set forth below:
  
  Number of Systems   Progress Status
  -----------------   ---------------
       151 Systems    Y2K Ready
        49 Systems    In Testing
        26 Systems    In Active Code Modification, or
                      Package Upgrading
  
       The Company  has been  experiencing  slippage  in delivery  dates of vendor
  supplied  products  which may have a minor  impact  on the July 1,  1999  target
  completion  date.  Contingency  planning  for  IT  Systems  is  scheduled  to be
  completed by July 1, 1999.
  
       The remaining 137 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
  -----------------   ---------------
        78 Systems    Y2K Ready
        25 Systems    In Final Quality Review
        29 Systems    In Progress
         5 Systems    Not Started
  
  Contingency  planning  for Embedded  Technology  is scheduled to be completed by
  July 1, 1999.
  
       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 is currently working with
  critical  suppliers on contingency  plans which are scheduled to be completed by
  July 1, 1999.
  
       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.
  
                                         18
  <PAGE>
  
       The  estimated  total cost of the Project is $75  million,  the majority of
  which will be incurred  during  testing.  This  estimate  includes the Company's
  share of Y2K costs for jointly owned  facilities.  The total amount  expended on
  the Project through March 31, 1999 was $33 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 order  requires,  (1) a written  response to a list of  compliance
  program questions by August 6, 1998 and, (2) all jurisdictional  fixed utilities
  be Year 2000  compliant  by March 31,  1999 or,  if a  utility  determines  that
  mission-critical  systems  cannot be Year 2000  compliant on or before March 31,
  1999,  the  utility is  required to file a detailed  contingency  plan.  The PUC
  adopted the federal government's definition for Year 2000 compliance and further
  defined  Year  2000   compliance  as  a   jurisdictional   utility   having  all
  mission-critical  Year 2000 hardware and software  updates  and/or  replacements
  installed and tested on or before March 31, 1999. On August 6, 1998, the Company
  filed  its  written  response,  in which  the  Company  stated  that  with a few
  carefully-assessed  and  closely-managed  exceptions,  the Company will have all
  mission-critical  systems  Year 2000 ready by June 1999.  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  
  
                                         19
  
  <PAGE>
  
  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 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
  NEI/NUSMG  97.07,  (2) the program is receiving  proper  management  support and
  oversight, and (3) project schedules are being aggressively pursued.
  
       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, 6 and 7 of
  Notes to Condensed Consolidated Financial Statements and other factors discussed
  in the Company's  filings with the SEC. Readers are cautioned not to place undue
  reliance on these forward-looking statements, which speak only as of the date of
  this  Report.  The Company  undertakes  no  obligation  to publicly  release any
  revision to these forward-looking  statements to reflect events or circumstances
  after the date of this Report.
  
                                         20
  <PAGE>
  ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
  
       The Company has entered into  interest  rate swaps to manage  interest rate
  exposure  associated with the issuance of two floating rate series of Transition
  Bonds.  The fair value of $5 million was based on the present  value  difference
  between the  contracted  rate (i.e.,  hedged rate) and the market rates at March
  31, 1999.
  
       The aggregate  change in fair value of these  derivative  instruments  that
  would have  resulted  from a  hypothetical  50 basis point  decrease in the spot
  yield at March 31, 1999 is estimated  to be $ 38.2  million.  If the  derivative
  instruments  had been  terminated at March 31, 1999,  this  estimated fair value
  represents the amount to be paid by the Company to the counterparties.
  
       The  aggregate  change  in fair  value of the  Transition  Bond  derivative
  instruments that would have resulted from a hypothetical 50 basis point increase
  in the spot yield at March 31, 1999 is  estimated  to be $45.9  million.  If the
  derivative  instruments  had been  terminated at March 31, 1999,  this estimated
  fair  value  represents  the  amount  to be  paid by the  counterparties  to the
  Company.
  
       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.
  
  
                                         21
  <PAGE>
  PART II - OTHER INFORMATION
  
  ITEM 1.  LEGAL PROCEEDINGS
       As  previously  reported,  on  April  9,  1998,  Grays  Ferry  Cogeneration
  Partnership   (Grays   Ferry),   two  of  three  partners  of  Grays  Ferry  and
  Trigen-Philadelphia Energy Corporation, filed a complaint in Philadelphia County
  Court  of  Common  Pleas  against  the  Company  arising  out of  the  Company's
  termination of two power purchase  agreements  that the Company had entered into
  with Grays Ferry.  
  
       On April 23,  1999,  the  Company  and  Grays  Ferry  entered  into a final
  settlement of the litigation.  The settlement  results in the restructuring of a
  power  purchase  agreement  through  which the Company is  currently  purchasing
  energy and  capacity.  The  settlement  also  provides  for the  transfer of the
  Company's  interest in the  partnership  to the  partnership.  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  settlement   also  resolves  the  litigation   with
  Westinghouse Power Generation and The Chase Manhattan Bank.
  
  ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
  
       On  April  27,  1999,   the  Company  held  its  1999  Annual   Meeting  of
  Shareholders.
  
       The following  Class III directors of the Company were re-elected for terms
  expiring in 2002:
  
                                       Votes For             Votes Withheld
                                       ---------             --------------
  Daniel L. Cooper                    180,230,306               1,936,445
  M. Walter D'Alessio                 180,150,467               2,096,123
  Ronald Rubin                        180,162,063               2,072,931
  
       The incumbent Class II directors, with terms expiring in 2001, are Susan W.
  Catherwood,  G. Fred DiBona, Jr., R. Keith Elliott,  John M. Palms and Joseph F.
  Paquette,  Jr. The incumbent  Class I directors with terms expiring in 2000, are
  Richard H. Glanton, Rosemarie B. Greco, Corbin A. McNeill, Jr. And Robert Subin.
  Other items voted on by holders of common  stock at the Annual  Meeting  were as
  follows:
  (1)  The  appointment  of  the  firm  PricewaterhouseCoopers,  LLP,  independent
       certified  public  accountants,  as auditors  of the Company for 1999,  was
       approved   with   180,396,466   common   shares  (80.2%  of  common  shares
       outstanding)  voting for;  650,651  common  shares  (0.3% of common  shares
       outstanding)  voting against;  and 1,019,788  common shares (0.5% of common
       shares outstanding) abstaining;
  (2)  A shareholder proposal requesting the Company to establish a firm policy to
       refuse  to use  mixed-oxide  fuel in the  Company's  nuclear  reactors  was
       defeated with 7,482,482  common shares (3.3% of common shares  outstanding)
       voting for;  129,078,299 common shares (57.4% of common shares outstanding)
       voting   against;   10,074,011   common   shares  (4.5%  of  common  shares
       outstanding)  abstaining;  and  35,432,113  common  shares (15.8% of common
       shares outstanding) broker votes.
  
                                         22
  <PAGE>
  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.
  
  
  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  March 8, 1999  reporting  information  under "ITEM 5. OTHER
           EVENTS" regarding the denial of an intervenor's petition for certiorari
           by the United States Supreme Court.
  
       Report,  dated March 25, 1999  reporting  information  under "ITEM 5. OTHER
           EVENTS"  regarding  the  securitization  of $4 billion of the Company's
           recoverable  stranded  costs  through  the  issuance  of $4  billion of
           Transition  Bonds  by PECO  Energy  Transition  Trust,  an  independent
           special purpose entity formed by the Company.
  
       Reports on Form 8-K filed subsequent to 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.
  
  
                                         23
  <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/ Jean H. Gibson
                                         ------------------
                                         JEAN H. GIBSON
                                         Vice President and
                                         Controller 
                                         (Chief Accounting Officer)
  
  Date:  May 14, 1999
  
  
                                         24
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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 March 31, 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 191,812,306 shares of common stock outstanding on May 7, 1999.
  PART I. FINANCIAL INFORMATION
                            ITEM 1. FINANCIAL STATEMENTS
                    PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
                     CONDENSED CONSOLIDATED STATEMENTS OF INCOME
                                     (Unaudited)
                                (Millions of Dollars)
  Three Months Ended
                                                                 March 31,
                                                        --------------------------
                                                            1999           1998
                                                        -----------    -----------
  OPERATING REVENUES
       Electric                                         $   1,038.9    $   1,003.0
       Gas                                                    217.5          187.2
                                                        -----------    -----------
       TOTAL OPERATING REVENUES                             1,256.4        1,190.2
                                                        -----------    -----------
  OPERATING EXPENSES
       Fuel and Energy Interchange                            465.1          383.0
       Operating and Maintenance                              288.7          283.2
       Depreciation and Amortization                           56.3          154.7
       Taxes Other Than Income Taxes                           75.3           82.1
                                                        -----------    -----------
       TOTAL OPERATING EXPENSES                               885.4          903.0
                                                        -----------    -----------
  OPERATING INCOME                                            371.0          287.2
                                                        -----------    -----------
  OTHER INCOME AND DEDUCTIONS
       Interest Expense                                       (74.3)         (85.0)
       Company Obligated Mandatorily Redeemable
         Preferred Securities of a Partnership                 (7.4)          (7.7)
       Allowance for Funds Used During Construction             0.4            0.6
       Other, Net                                             (42.0)         (12.8)
                                                        -----------    -----------
       TOTAL OTHER INCOME AND DEDUCTIONS                     (123.3)        (104.9)
                                                        -----------    -----------
  INCOME BEFORE INCOME TAXES                                  247.7          182.3
  
  INCOME TAXES                                                 98.0           68.7
                                                        -----------    -----------
  NET INCOME                                                  149.7          113.6
  
  PREFERRED STOCK DIVIDENDS                                     3.3            3.3
                                                        -----------    -----------
  EARNINGS APPLICABLE TO COMMON STOCK                   $     146.4    $     110.3
                                                        ===========    ===========
  
  AVERAGE SHARES OF COMMON STOCK
       OUTSTANDING  (Millions)                                223.4          222.5
                                                        ===========    ===========
  
  BASIC EARNINGS PER AVERAGE
  COMMON SHARE (Dollars)                                $      0.66    $      0.50
                                                        ===========    ===========
  
  DILUTIVE EARNINGS PER AVERAGE
  COMMON SHARE (Dollars)                                $      0.65    $      0.50
                                                        ===========    ===========
  
  DIVIDENDS PER AVERAGE COMMON SHARE (Dollars)          $      0.25    $      0.25
                                                        ===========    ===========
  
  BOOK VALUE PER COMMON SHARE (Dollars)                 $     12.18    $     12.49
                                                        ===========    ===========
  See Notes to Condensed Consolidated Financial Statements.
  
                                         2
  PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
                        CONDENSED CONSOLIDATED BALANCE SHEETS
                                (Millions of Dollars)
  March 31,    December 31,
                                                            1999          1998
                                                         -----------   -----------
                                                         (Unaudited)
  ASSETS
  
  UTILITY PLANT
  Electric - Transmission & Distribution                 $   3,870.8   $   3,833.8
  Electric - Generation                                      1,722.0       1,713.4
  Gas                                                        1,138.2       1,132.0
  Common                                                       408.7         407.3
                                                         -----------   -----------
  
                                                             7,139.7       7,086.5
  Less Accumulated Provision for Depreciation                2,950.7       2,891.3
                                                         -----------   -----------
  
                                                             4,189.0       4,195.2
  Nuclear Fuel, net                                            128.0         141.9
  Construction Work in Progress                                290.1         272.6
  Leased Property, net                                         138.3         154.3
                                                         -----------   -----------
  
                                                             4,745.4       4,764.0
                                                         -----------   -----------
  
  CURRENT ASSETS
  Cash and Temporary Cash Investments                        2,702.8          48.1
  Accounts Receivable, net
       Customer                                                183.0          97.5
       Other                                                   262.5         213.2
  Inventories, at average cost
       Fossil Fuel                                              84.9          92.3
       Materials and Supplies                                   83.1          82.1
  Deferred Energy Costs - Gas                                    0.8          29.9
  Other                                                        188.7          19.0
                                                         -----------   -----------
  
                                                             3,505.8         582.1
                                                         -----------   -----------
  
  DEFERRED DEBITS AND OTHER ASSETS
  Competitive Transition Charge                              5,274.6       5,274.6
  Recoverable Deferred Income Taxes                            613.9         614.4
  Deferred Non-Pension Postretirement Benefits Costs            89.3          90.9
  Investments                                                  534.0         538.1
  Loss on Reacquired Debt                                       75.6          77.2
  Other                                                        132.7         107.1
                                                         -----------   -----------
  
                                                             6,720.1       6,702.3
                                                         -----------   -----------
  
  TOTAL                                                  $  14,971.3   $  12,048.4
                                                         ===========   ===========
  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)
  March 31,      December 31,
                                                        1999            1998
                                                     -----------    -----------
                                                     (Unaudited)
  CAPITALIZATION AND LIABILITIES
  
  CAPITALIZATION
  Common Shareholders' Equity
       Common Stock (No Par)                         $   3,602.6    $   3,589.0
       Other Paid-In Capital                                 1.2            1.2
       Accumulated Deficit                                (429.3)        (532.9)
       Treasury Stock                                     (695.9)            --
  Preferred and Preference Stock
       Without Mandatory Redemption                        137.5          137.5
       With Mandatory Redemption                            92.7           92.7
  Company Obligated Mandatorily Redeemable
       Preferred Securities of a Partnership               349.4          349.4
  Long-Term Debt                                         6,084.0        2,919.6
                                                     -----------    -----------
  
                                                         9,142.2        6,556.5
                                                     -----------    -----------
  
  CURRENT LIABILITIES
  Notes Payable, Bank                                       68.0          525.0
  Long-Term Debt Due Within One Year                       939.4          361.5
  Capital Lease Obligations Due Within One Year             68.8           69.0
  Accounts Payable                                         276.9          316.2
  Taxes Accrued                                            342.0          170.5
  Interest Accrued                                          67.1           61.5
  Deferred Income Taxes                                      4.0           14.1
  Other                                                    236.6          217.4
                                                     -----------    -----------
  
                                                         2,002.8        1,735.2
                                                     -----------    -----------
  
  DEFERRED CREDITS AND OTHER LIABILITIES
  Capital Lease Obligations                                 69.5           85.3
  Deferred Income Taxes                                  2,362.5        2,376.9
  Unamortized Investment Tax Credits                       296.4          300.0
  Pension Obligation                                       219.3          219.3
  Non-Pension Postretirement Benefits Obligation           428.6          421.1
  Other                                                    450.0          354.1
                                                     -----------    -----------
  
                                                         3,826.3        3,756.7
                                                     -----------    -----------
  
  COMMITMENTS AND CONTINGENCIES (NOTE 6)
  
  TOTAL                                              $  14,971.3    $  12,048.4
                                                     ===========    ===========
  See Notes to Condensed Consolidated Financial Statements.
  
                                         4
  PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
                   CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
                                     (Unaudited)
                                (Millions of Dollars)
  Three Months Ended
                                                                        March 31,
                                                                ----------------------
                                                                    1999         1998
                                                                ----------    --------
  CASH FLOWS FROM OPERATING ACTIVITIES
  
  NET INCOME                                                    $    149.7    $  113.6
  Adjustments to Reconcile Net Income to Net Cash
       Provided by Operating Activities:
  Depreciation and Amortization                                       73.9       170.9
  Deferred Income Taxes                                              (23.0)       (6.8)
  Amortization of Investment Tax Credits                              (3.6)       (4.5)
  Deferred Energy Costs                                               29.0        19.0
  Changes in Working Capital:
       Accounts Receivable                                          (134.7)       24.9
       Inventories                                                     6.4        17.7
       Accounts Payable                                              (39.3)      (74.4)
       Other Current Assets and Liabilities                           35.6       (45.5)
  Other Items Affecting Operations                                    88.4        16.2
                                                                ----------    --------
  
  CASH FLOWS PROVIDED BY OPERATING ACTIVITIES                        182.4       231.1
                                                                ----------    --------
  
  CASH FLOWS FROM INVESTING ACTIVITIES
  
  Investment in Plant                                                (76.9)     (116.5)
  Increase in Investments                                             (5.3)      (11.1)
                                                                ----------    --------
  
  NET CASH FLOWS USED IN INVESTING ACTIVITIES                        (82.2)     (127.6)
                                                                ----------    --------
  
  CASH FLOWS FROM FINANCING ACTIVITIES
  
  Change in Short-Term Debt                                         (457.0)      (17.0)
  Issuance of Long-Term Debt                                       4,009.6        (5.5)
  Retirement of Long-Term Debt                                      (263.0)         --
  Common Stock Repurchase                                           (695.9)         --
  Loss on Reacquired Debt                                              1.6         1.8
  Dividends on Preferred and Common Stock                            (59.5)      (58.9)
  Other Items Affecting Financing                                     18.7        (2.3)
                                                                ----------    --------
  
  NET CASH FLOWS PROVIDED BY (USED IN) FINANCING ACTIVITIES        2,554.5       (81.9)
                                                                ----------    --------
  
  INCREASE IN CASH AND CASH EQUIVALENTS                            2,654.7        21.6
                                                                ----------    --------
  
  CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD                    48.1        33.4
                                                                ----------    --------
  
  CASH AND CASH EQUIVALENTS AT END OF PERIOD                    $  2,702.8    $   55.0
                                                                ==========    ========
  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 March
  31,  1999 and for the three  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 (1998
  Form 10-K).
  
  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 March 31,
       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  will be  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.  The fair value of $5 million was based on the present  value  difference
  between the  contracted  rate (i.e.,  hedged rate) and the market rates at March
  31, 1999.
  
       The  aggregate  change  in fair  value of the  Transition  Bond  derivative
  instruments that would have resulted from a hypothetical 50 basis point decrease
  in the spot yield at March 31, 1999 is  estimated  to be $38.2  million.  If the
  derivative  instruments  had been  terminated at March 31, 1999,  this estimated
  fair  value   represents   the  amount  to  be  paid  by  the   Company  to  the
  counterparties.
  
       The aggregate  change in fair value of these  derivative  instruments  that
  would have  resulted  from a  hypothetical  50 basis point  increase in the spot
  yield at March 31, 1999 is  estimated  to be $45.9  million.  If the  derivative
  instruments  had been  terminated at March 31, 1999,  this  estimated fair value
  represents 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 $3.9 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.  On March 26, 1999, the Company
  settled the forward purchase  agreements  relating to its Common Stock resulting
  in the  purchase by the Company of 21.5  million  shares of Common  Stock for an
  aggregate purchase price of $696 million. In addition, the Company repaid a $400
  million term loan,  $208 million of  commercial  paper,  $48 million of accounts
  receivable  financing and paid $21 million of debt issuance costs. The remaining
  proceeds of $2.6 billion are  included in cash at March 31,  1999.  On March 26,
  1999, the Company called for redemption four series of its First Mortgage Bonds,
  7.75% Series due 2023,  7.25% Series due 2024,  7.125% Series due 2023 and 7.75%
  Series 2 due 2023, totaling $775 million.
  
  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.
  
                                         7
  During the first quarter of 1999, the Company completed the redesign of its
  internal  reporting  structure to separate  its  distribution,  generation,  and
  ventures  operations  into business units and provide  financial and operational
  data on the same basis to senior management. The Company's distribution business
  unit 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 generating 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.
  
       The  Company's  segment  information  as of and for the three  months ended
  March 31, 1999 as compared to the same 1998 period is as follows (in millions of
  dollars):
  Intersegment
                        Distribution         Generation        Ventures         Corporate        Revenues       Consolidated
                        ------------         ----------        --------         ---------        --------       ------------
  Revenues:
      1999                 $910.1              $443.9            $103.8           $ -            $(201.4)         $1,256.4
      1998                 $949.5              $465.0            $ 17.0           $ -            $(241.3)         $1,190.2
  EBIT (a):
      1999                 $354.7              $ 46.5(b)        $( 30.6)(c)       $(41.6)                         $  329.0
      1998                 $307.3              $ 41.4           $( 27.5)          $(46.8)                         $  274.4
  Total Assets:                                                                  
      1999              $12,366.3(d)         $1,919.5            $246.7           $438.8                         $14,971.3
      1998              $ 9,759.2            $1,686.8            $216.9           $385.5                         $12,048.4
  (a)  EBIT - Earnings Before Interest and Income Taxes.
  (b)  Includes an $11.8 million reserve related to the Grays Ferry power purchase
       agreement.
  (c)  Includes $14.6 million  related to the write-off of the investment in Grays
       Ferry in connection with the settlement of litigation.
  (d)  Includes $2.6 billion of proceeds from securitization of stranded costs.
  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:
  
                                         8
  Three Months Ended
                                                   March 31,
                                              ------------------
                                               1999         1998
                                             -------      -------
                                              (Millions of shares)
  
  Average Common Shares Outstanding            223.4        222.5
  
  Assumed Conversion of Stock Options            1.3           -- 
                                             -------      -------
  
  Potential Average Dilutive
    Common Shares Outstanding                  224.7        222.5
                                             =======      =======
  
  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 $353 million of designated  accounts  receivable  until
  November 2000. At March 31, 1999,  the Company had sold a $353 million  interest
  in  accounts  receivable,  consisting  of a $289  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 $64 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 $353 million
  interest,  which,  if not met,  requires the Company to deposit cash in order to
  satisfy  such   requirements.   The  Company,   at  March  31,  1999,  met  such
  requirements.  At March  31,  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 5.05%.
  
  6.   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 March 31, 1999, the Company had entered into long-term  agreements  with
  unaffiliated   utilities  to  purchase   transmission   rights.  These  purchase
  commitments  result in  obligations  of  approximately  $47 million in 1999, $88
  million in 2000,  $22 million in 2001,  and $10 million per year in 2002 through
  2005.
  
       The Company has  identified  28 sites where former  manufactured  gas plant
  (MGP) activities have or may have resulted in actual site  contamination.  As of
  March  31,  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
  results in a restructuring of the power purchase  agreement  between the Company
  and Grays Ferry.  The settlement also provides for the transfer of the Company's
  interest  in  the  partnership  to the  partnership.  Accordingly,  the  
  
                                         9
  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 three months  ended March 31, 1999.  The  settlement
  also resolves the litigation with  Westinghouse  Power  Generation and The Chase
  Manhattan Bank.
  
  7.   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.  The new standard will be effective for fiscal years beginning after
  June 15, 1999. The Company expects to adopt SFAS No. 133 in the first quarter of
  2000.  The Company is in the process of evaluating the impact of SFAS No. 133 on
  its financial statements.
  
       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.
  
       At March 31,  1999,  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 not subject to EITF 98-10 or mark-to-market accounting.
  
                                         10
  The Company  records  revenues  and  expenses  with the energy  commitments
  consistent with when the underlying physical  transaction closes.  Additionally,
  the Company  evaluates its energy  commitments for impairment based on the lower
  of cost or market.  At March 31,  1998,  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.  During  1999,  two-thirds  of each class of the  Company's
  retail electric customers in its traditional service territory will 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  March  31,  1999
  approximately 13% of the Company's  residential  customers, approximately 22% of
  its commercial  customers and approximately 56% 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   138,000  business  and  residential   customers   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.
  
       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.
  
       During the first quarter of 1999, the Company completed the redesign of its
  internal  reporting  structure to separate  its  distribution,  generation,  and
  ventures  operations  into business units and provide  financial and operational
  data on the same basis to senior management. The Company's distribution business
  unit 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 generating 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.
  
  RESULTS OF OPERATIONS
  
       The  Company's  Statements  of Income for the three  months ended March 31,
  1998 reflect the reclassification of the results of operations of Exelon Energy,
  from Other Income and Deductions.
  
                                         12
  Revenue and Expense Items as a
  Percentage of Total Operating
  Revenues                                               Percentage Dollar Changes
        1999     1998                                            1999-1998
        ----     ----                                            ---------
  
         83%      84%           Electric                            4%
         17%      16%           Gas                                16%
       ----     ---- 
        100%     100%           Total Operating Revenues            6%
       ----     ---- 
  
         37%      32%           Fuel and Energy Interchange        21%
         23%      24%           Operating and Maintenance          (2%)
          4%      13%           Depreciation and Amortization     (62%)
          6%       7%           Taxes Other Than Income            (8%)
       ----     ---- 
         70%      76%           Total Operating Expenses           (2%)
       ----     ---- 
  
         30%      24%           Operating Income                   30%
       ----     ---- 
  
         (7%)     (8%)          Interest Expense                  (12%)
         (3%)     (1%)          Other Income and Deductions      (241%)
       ----     ---- 
         20%      15%           Income Before Income Taxes         36%
          8%       6%           Income Taxes                       43%
       ----     ---- 
         12%       9%           Net Income                         32%
       ----     ---- 
  
  Operating Revenues
       Electric revenues increased $36 million,  or 4%, for the three months ended
  March 31, 1999 compared to the same 1998 period.  The increase was  attributable
  to higher  revenues  from the  ventures  business  unit of $88  million  and the
  generation  business unit of $19 million,  partially offset by lower revenues at
  the  distribution  business unit of $71 million.  The increase from the ventures
  business unit was primarily from increased volume in Pennsylvania resulting from
  the  commencement  of the sale of competitive  electric  generation  services by
  Exelon Energy.  The increase from the generation  business unit was attributable
  to the marketing of excess generation  capacity as a result of lower native load
  requirements  as a result of  competition.  The decrease  from the  distribution
  business  unit was  attributable  to $68  million  as a result  of lower  volume
  associated  with the effects of  competition  and $56 million  related to the 8%
  across-the-board rate reduction mandated by the Final Restructuring Order. These
  decreases were partially offset by $36 million of PJM  Interconnection LLC (PJM)
  network  transmission  service  revenue  which  commenced  April 1, 1998 and $17
  million  related to  increased  sales  volume  from colder  weather  conditions.
  Stranded  cost  recovery is  included in the  Company's  retail  electric  rates
  beginning January 1, 1999.
  
       Gas  revenues  increased  $30  million,  or 16%, for the three months ended
  March 31, 1999  compared to the same 1998 period.  The  increase  was  primarily
  attributable to increased volume as a result of colder weather conditions of $20
  million and increased volume from new customers of $10 million.
  
                                         13
  Fuel and Energy Interchange Expense
       Fuel and energy interchange  expense increased $82 million, or 21%, for the
  three  months  ended  March 31,  1999  compared  to the same 1998  period.  As a
  percentage of revenue, fuel and interchange expenses were 37% as compared to 32%
  in the comparable prior year period. These increases were attributable to higher
  fuel and energy  interchange  expenses  from the ventures  business  unit of $69
  million and the distribution  business unit of $63 million,  partially offset by
  lower fuel and energy  interchange  expenses  of $50  million at the  generation
  business unit.  The increase from the ventures  business unit was primarily from
  increased  volume  related  to  Exelon  Energy  sales.  The  increase  from  the
  distribution  business  unit was  primarily  attributable  to $27 million of PJM
  network  transmission service fees which commenced April 1, 1998, $26 million of
  purchases in the spot market and $10 million of  additional  gas  purchases as a
  result of higher volume  associated with colder  weather.  The decrease from the
  generation business unit was primarily attributable to $78 million of lower fuel
  purchases  as a  result  of  the  effects  of  competition  experienced  by  the
  distribution  business unit. This increase was partially offset by a $12 million
  reserve related to the Grays Ferry power purchase  agreement and fuel savings of
  $16  million  from 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
       Operating and maintenance expense increased $6 million, or 2% for the three
  months ended March 31, 1999  compared to the same 1998 period.  The increase was
  primarily  attributable to increased information  technology expenses related to
  Year 2000  remediation of $12 million  partially offset by lower expenses at the
  generation business unit of $8 million as a result of the full return to service
  of Salem in April 1998.  As a percentage of revenue,  operating and  maintenance
  expenses were 23% as compared to 24% in the comparable prior year period.
  
  Depreciation and Amortization Expense
       Depreciation and amortization  expense  decreased $98 million,  or 64%, for
  the three  months ended March 31, 1999  compared to the same 1998  period.  As a
  percentage of revenue,  depreciation and amortization expense was 4% 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  established a regulatory  asset,
  Deferred  Generation Costs  Recoverable in Current Rates of $424 million,  which
  was fully  amortized in 1998, and 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 $7 million,  or 8%, for the three months
  ended  March 31, 1999  compared  to the same 1998  period.  As a  percentage  of
  revenue,  taxes other than income were 6%, as compared to 7%, in the  comparable
  prior year period.  The decrease was attributable to lower gross receipts tax of
  $3 million and lower capital stock tax of $4 million.
  
                                         14
  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
  decreased  $11  million,  or 12%,  for the three  months  ended  March 31,  1999
  compared to the same 1998 period.  As a percentage of revenue,  interest charges
  were 7% as compared to 8% in the  comparable  prior year period.  The  Company's
  ongoing program to reduce and/or refinance  higher cost,  long-term debt reduced
  interest charges by $16 million.  This decrease was partially offset by interest
  on the Transition Bonds of $5 million.
  
  Other Income and Deductions
       Other income and deductions  excluding  interest  charges was a loss of $42
  million for the three  months  ended March 31, 1999 as compared to a loss of $13
  million in the same 1998  period.  The  decrease of $29  million  was  primarily
  attributable  to the  write-off of the  investment  in Grays Ferry in connection
  with  the  settlement  of  litigation  of $15  million,  the  abandonment  of an
  information  system of $7 million and additional losses from equity  investments
  in  telecommunications  ventures and non-utility  operations of $7 million. As a
  percentage of revenue,  other income and deductions were 3% as compared to 1% in
  the comparable prior year period.
  
  Income Taxes
       The effective  tax rate was  proportionate  to the  statutory  rate for the
  three  months  ended March 31, 1999 as compared to 38% in the same 1998  period.
  The  effective  tax  rate  for  the  three  months  ended  March  31,  1998  was
  disproportionate  to the statutory rate as a result of the full normalization of
  deferred taxes associated with deregulated  generation plant and amortization of
  investment tax credits.
  
  Preferred Stock Dividends
       Preferred  stock  dividends  for the three months ended March 31, 1999 were
  consistent with the same 1998 period.
  
  DISCUSSION OF LIQUIDITY AND CAPITAL RESOURCES
       Cash flows provided by operating  activities  decreased $49 million to $182
  million for the three months ended March 31, 1999 as compared to $231 million in
  the same 1998  period.  The  decrease was  primarily  attributable  to less cash
  generated  by  operations  of $66  million,  changes in  working  capital of $55
  million  principally  related to the  timing of gross  receipts  tax,  partially
  offset  by  other  items  affecting  operations  of  $72  million,   principally
  consisting  of the  deferred  gain  on the  unwinding  of  interest  rate  swaps
  associated with the issuance of Transition Bonds.
  
       Cash flows used by  investing  activities  were $82  million  for the three
  months ended March 31, 1999 as compared to $128 million in the  comparable  1998
  period.  Expenditures under the Company's  construction program decreased to $77
  million in the current period.
  
                                         15
  Cash flows provided by financing activities were $2,555 million as compared
  to cash used in financing activities of $82 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  $720 million and the  settlement  of the Company's
  common stock forward purchase contract for $696 million.
  
       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 from  variable  distribution  charges  (both of  which  are  usage-based
  charges).
  
       PETT used the $3.99 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%.
  Concurrently  with the issuance of the  Transition  Bonds,  the Company repaid a
  $400 million  term loan,  $208  million of  commercial  paper and $48 million of
  accounts  receivable  financing  and  repurchased  21.5  shares of common  stock
  pursuant to forward  repurchase  arrangements for an aggregate purchase price of
  $696 million.  The Company also called for redemption $ 775 million of its First
  Mortgage  Bonds as follows:  7.75%  Series due 2023,  7.25%  Series due 2024 and
  7.125%  Series due 2023 on April 26, 1999 and 7.75%  Series 2 due 2023 on May 3,
  1999.  The Company  also plans to call for  redemption  its COMRPS 9% Series due
  2043 on August 1, 1999. The Company currently  anticipates that it will complete
  the repurchase of common equity through open market  purchases from time to time
  in compliance  with  Securities  and Exchange  Commission  rules.  The number of
  shares  purchased  and the timing and manner or  purchases  are  dependent  upon
  market conditions.
  
       Although the Company has sold the ITP to PETT, the ITC revenue,  as well as
  all interest  expense and  amortization  expense  associated with the Transition
  Bonds, will be reflected on the Company's  Consolidated Statement of Income. The
  combined  schedule  for  amortization  of the  CTC  and  ITC  assets  will be 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  proposed
  capital reduction by the Company, the Company expects its debt-to-total  capital
  ratio to be 60% upon  completion  of the  application  of the proceeds  from the
  securitization.  The  Company  currently  projects  that  it will  complete  the
  majority of the targeted  debt and  preferred  security  reductions by August 1,
  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 additional expense, combined with the anticipated
  
                                         16
  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.
  
       At March 31,  1999,  the  Company  had  outstanding  $68  million  of notes
  payable, all of which were commercial paper. In addition, at March 31, 1999, the
  Company had formal and informal lines of bank credit  aggregating  $100 million.
  At March 31, 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
       Due to the  severity  of the  potential  impact of the Year 2000 Issue (Y2K
  Issue) on the electric utility industry, the Company has adopted a comprehensive
  schedule to achieve Y2K readiness by the time  specified by the NRC. The Company
  has dedicated  extensive resources to its Y2K Project (Project) and believes the
  Project  is  progressing  on  schedule.  The  Project  is  addressing  the issue
  resulting from computer programs using two digits rather than four to define the
  applicable   year  and  other   programming   techniques   that  constrain  date
  calculations or assign special  meanings to certain dates.  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.
  
       The Company has determined  that it will be 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 is
  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 Project is divided into four major  sections -  Information  Technology
  Systems (IT Systems),  Embedded Technology (devices used to control,  monitor or
  assist  the   operation  of  equipment,   machinery  or  plant),   Supply  Chain
  (third-party  suppliers and customers),  and Contingency  Planning.  The general
  phases common to all sections  are: (1)  inventorying  Y2K items;  (2) assigning
  priorities  to  identified  items;  (3)  assessing  the Y2K  readiness  of items
  
                                         17
  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 226
  are IT Systems. The current readiness status of IT Systems is set forth below:
  
  Number of Systems   Progress Status
  -----------------   ---------------
       151 Systems    Y2K Ready
        49 Systems    In Testing
        26 Systems    In Active Code Modification, or
                      Package Upgrading
  
       The Company  has been  experiencing  slippage  in delivery  dates of vendor
  supplied  products  which may have a minor  impact  on the July 1,  1999  target
  completion  date.  Contingency  planning  for  IT  Systems  is  scheduled  to be
  completed by July 1, 1999.
  
       The remaining 137 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
  -----------------   ---------------
        78 Systems    Y2K Ready
        25 Systems    In Final Quality Review
        29 Systems    In Progress
         5 Systems    Not Started
  
  Contingency  planning  for Embedded  Technology  is scheduled to be completed by
  July 1, 1999.
  
       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 is currently working with
  critical  suppliers on contingency  plans which are scheduled to be completed by
  July 1, 1999.
  
       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.
  
                                         18
  The  estimated  total cost of the Project is $75  million,  the majority of
  which will be incurred  during  testing.  This  estimate  includes the Company's
  share of Y2K costs for jointly owned  facilities.  The total amount  expended on
  the Project through March 31, 1999 was $33 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 order  requires,  (1) a written  response to a list of  compliance
  program questions by August 6, 1998 and, (2) all jurisdictional  fixed utilities
  be Year 2000  compliant  by March 31,  1999 or,  if a  utility  determines  that
  mission-critical  systems  cannot be Year 2000  compliant on or before March 31,
  1999,  the  utility is  required to file a detailed  contingency  plan.  The PUC
  adopted the federal government's definition for Year 2000 compliance and further
  defined  Year  2000   compliance  as  a   jurisdictional   utility   having  all
  mission-critical  Year 2000 hardware and software  updates  and/or  replacements
  installed and tested on or before March 31, 1999. On August 6, 1998, the Company
  filed  its  written  response,  in which  the  Company  stated  that  with a few
  carefully-assessed  and  closely-managed  exceptions,  the Company will have all
  mission-critical  systems  Year 2000 ready by June 1999.  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  
  
                                         19
  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 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
  NEI/NUSMG  97.07,  (2) the program is receiving  proper  management  support and
  oversight, and (3) project schedules are being aggressively pursued.
  
       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, 6 and 7 of
  Notes to Condensed Consolidated Financial Statements and other factors discussed
  in the Company's  filings with the SEC. Readers are cautioned not to place undue
  reliance on these forward-looking statements, which speak only as of the date of
  this  Report.  The Company  undertakes  no  obligation  to publicly  release any
  revision to these forward-looking  statements to reflect events or circumstances
  after the date of this Report.
  
                                         20
  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.  The fair value of $5 million was based on the present  value  difference
  between the  contracted  rate (i.e.,  hedged rate) and the market rates at March
  31, 1999.
  
       The aggregate  change in fair value of these  derivative  instruments  that
  would have  resulted  from a  hypothetical  50 basis point  decrease in the spot
  yield at March 31, 1999 is estimated  to be $ 38.2  million.  If the  derivative
  instruments  had been  terminated at March 31, 1999,  this  estimated fair value
  represents the amount to be paid by the Company to the counterparties.
  
       The  aggregate  change  in fair  value of the  Transition  Bond  derivative
  instruments that would have resulted from a hypothetical 50 basis point increase
  in the spot yield at March 31, 1999 is  estimated  to be $45.9  million.  If the
  derivative  instruments  had been  terminated at March 31, 1999,  this estimated
  fair  value  represents  the  amount  to be  paid by the  counterparties  to the
  Company.
  
       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.
  
                                         21
  PART II - OTHER INFORMATION
  
  ITEM 1.  LEGAL PROCEEDINGS
       As  previously  reported,  on  April  9,  1998,  Grays  Ferry  Cogeneration
  Partnership   (Grays   Ferry),   two  of  three  partners  of  Grays  Ferry  and
  Trigen-Philadelphia Energy Corporation, filed a complaint in Philadelphia County
  Court  of  Common  Pleas  against  the  Company  arising  out of  the  Company's
  termination of two power purchase  agreements  that the Company had entered into
  with Grays Ferry.  
  
       On April 23,  1999,  the  Company  and  Grays  Ferry  entered  into a final
  settlement of the litigation.  The settlement  results in the restructuring of a
  power  purchase  agreement  through  which the Company is  currently  purchasing
  energy and  capacity.  The  settlement  also  provides  for the  transfer of the
  Company's  interest in the  partnership  to the  partnership.  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  settlement   also  resolves  the  litigation   with
  Westinghouse Power Generation and The Chase Manhattan Bank.
  
  ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
  
       On  April  27,  1999,   the  Company  held  its  1999  Annual   Meeting  of
  Shareholders.
  
       The following  Class III directors of the Company were re-elected for terms
  expiring in 2002:
  
                                       Votes For             Votes Withheld
                                       ---------             --------------
  Daniel L. Cooper                    180,230,306               1,936,445
  M. Walter D'Alessio                 180,150,467               2,096,123
  Ronald Rubin                        180,162,063               2,072,931
  
       The incumbent Class II directors, with terms expiring in 2001, are Susan W.
  Catherwood,  G. Fred DiBona, Jr., R. Keith Elliott,  John M. Palms and Joseph F.
  Paquette,  Jr. The incumbent  Class I directors with terms expiring in 2000, are
  Richard H. Glanton, Rosemarie B. Greco, Corbin A. McNeill, Jr. And Robert Subin.
  Other items voted on by holders of common  stock at the Annual  Meeting  were as
  follows:
  (1)  The  appointment  of  the  firm  PricewaterhouseCoopers,  LLP,  independent
       certified  public  accountants,  as auditors  of the Company for 1999,  was
       approved   with   180,396,466   common   shares  (80.2%  of  common  shares
       outstanding)  voting for;  650,651  common  shares  (0.3% of common  shares
       outstanding)  voting against;  and 1,019,788  common shares (0.5% of common
       shares outstanding) abstaining;
  (2)  A shareholder proposal requesting the Company to establish a firm policy to
       refuse  to use  mixed-oxide  fuel in the  Company's  nuclear  reactors  was
       defeated with 7,482,482  common shares (3.3% of common shares  outstanding)
       voting for;  129,078,299 common shares (57.4% of common shares outstanding)
       voting   against;   10,074,011   common   shares  (4.5%  of  common  shares
       outstanding)  abstaining;  and  35,432,113  common  shares (15.8% of common
       shares outstanding) broker votes.
  
                                         22
  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.
  
  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  March 8, 1999  reporting  information  under "ITEM 5. OTHER
           EVENTS" regarding the denial of an intervenor's petition for certiorari
           by the United States Supreme Court.
  
       Report,  dated March 25, 1999  reporting  information  under "ITEM 5. OTHER
           EVENTS"  regarding  the  securitization  of $4 billion of the Company's
           recoverable  stranded  costs  through  the  issuance  of $4  billion of
           Transition  Bonds  by PECO  Energy  Transition  Trust,  an  independent
           special purpose entity formed by the Company.
  
       Reports on Form 8-K filed subsequent to 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.
  
                                         23
  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/ Jean H. Gibson
                                         ------------------
                                         JEAN H. GIBSON
                                         Vice President and
                                         Controller 
                                         (Chief Accounting Officer)
  
  Date:  May 14, 1999
  
                                         24