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.


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<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.

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<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.


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<PAGE>

                                   Signatures

     Pursuant  to  requirements  of the  Securities  Exchange  Act of 1934,  the
registrant  has duly  caused  this  report  to be  signed  on its  behalf by the
undersigned thereunto duly authorized.




                                       PECO ENERGY COMPANY
                                       /s/ Jean H. Gibson
                                       ------------------
                                       JEAN H. GIBSON
                                       Vice President and
                                       Controller 
                                       (Chief Accounting Officer)

Date:  May 14, 1999


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