UNITED STATES SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

                                    FORM 10-Q

                   [X] QUARTERLY REPORT PURSUANT TO SECTION 13
                     OR 15(d) OF THE SECURITIES EXCHANGE ACT
                                     OF 1934
                  For the Quarterly Period Ended June 30, 2003
                                       OR
          [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
                         SECURITIES EXCHANGE ACT OF 1934

<TABLE>
<CAPTION>


     Commission                 Name of Registrant; State of Incorporation;                  IRS Employer
     File Number                Address of Principal Executive Offices; and                  Identification
                                Telephone Number                                             Number
---------------------      ---------------------------------------------------------    ------------------------
<S>                           <C>                                                           <C>
     1-16169                    EXELON CORPORATION                                           23-2990190
                                (a Pennsylvania corporation)
                                10 South Dearborn Street - 37th Floor
                                P.O. Box 805379
                                Chicago, Illinois 60680-5379
                                (312) 394-7398

     1-1839                     COMMONWEALTH EDISON COMPANY                                  36-0938600
                                (an Illinois corporation)
                                10 South Dearborn Street - 37th Floor
                                P.O. Box 805379
                                Chicago, Illinois 60680-5379
                                (312) 394-4321

     1-1401                     PECO ENERGY COMPANY                                          23-0970240
                                (a Pennsylvania corporation)
                                P.O. Box 8699 2301 Market Street
                                Philadelphia, Pennsylvania 19101-8699
                                (215) 841-4000

     333-85496                  EXELON GENERATION COMPANY, LLC                               23-3064219
                                (a Pennsylvania limited liability company)
                                300 Exelon Way
                                Kennett Square, Pennsylvania 19348
                                (610) 765-6900

</TABLE>


     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 [_].

     The number of shares outstanding of each registrant's common stock as of
     June 30, 2003 was:

     Exelon Corporation Common Stock, without par value          325,848,491
     Commonwealth Edison Company Common Stock, $12.50 par value  127,016,429
     PECO Energy Company Common Stock, without par value         170,478,507
     Exelon Generation Company, LLC                              not applicable

     Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). Exelon Corporation Yes [X] No [ ]
Commonwealth Edison Company, PECO Energy Company and Exelon Generation Company,
LLC Yes [ ] No [X].


<PAGE>



                                                  TABLE OF CONTENTS

<TABLE>
<CAPTION>

                                                                                                                   Page No.
                                                                                                                   --------
<S>                                                                                                                   <C>
      FILING FORMAT                                                                                                   3
      FORWARD-LOOKING STATEMENTS                                                                                      3
      WHERE TO FIND MORE INFORMATION                                                                                  3

      PART I.   FINANCIAL INFORMATION                                                                                 4
      ITEM 1.   FINANCIAL STATEMENTS                                                                                  4
                      Exelon Corporation
                               Consolidated Statements of Income and Comprehensive Income                             5
                               Consolidated Statements of Cash Flows                                                  6
                               Consolidated Balance Sheets                                                            7
                      Commonwealth Edison Company
                               Consolidated Statements of Income and Comprehensive Income                             9
                               Consolidated Statements of Cash Flows                                                 10
                               Consolidated Balance Sheets                                                           11
                      PECO Energy Company
                               Consolidated Statements of Income and Comprehensive Income                            13
                               Consolidated Statements of Cash Flows                                                 14
                               Consolidated Balance Sheets                                                           15
                      Exelon Generation Company, LLC
                               Consolidated Statements of Income and Comprehensive Income                            17
                               Consolidated Statements of Cash Flows                                                 18
                               Consolidated Balance Sheets                                                           19
                      Condensed Combined Notes to Consolidated Financial Statements                                  21

     ITEM 2.   MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
                AND RESULTS OF OPERATIONS                                                                            61
                      Exelon Corporation                                                                             61
                      Commonwealth Edison Company                                                                    90
                      PECO Energy Company                                                                           105
                      Exelon Generation Company, LLC                                                                120

      ITEM 3.   QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK                                           135
      ITEM 4.   CONTROLS AND PROCEDURES                                                                             147

      PART II.  OTHER INFORMATION                                                                                   150
      ITEM 1.   LEGAL PROCEEDINGS                                                                                   150
      ITEM 4.   SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS                                                 150
      ITEM 5.   OTHER INFORMATION                                                                                   152
      ITEM 6.   EXHIBITS AND REPORTS ON FORM 8-K                                                                    153

     SIGNATURES                                                                                                     156



</TABLE>

                                       2
<PAGE>



     FILING FORMAT
              This combined Form 10-Q is being filed separately by Exelon
     Corporation (Exelon), Commonwealth Edison Company (ComEd), PECO Energy
     Company (PECO) and Exelon Generation Company, LLC (Generation)
     (Registrants). Information contained herein relating to any individual
     registrant has been filed by such registrant on its own behalf. No
     registrant makes any representation as to information relating to any other
     registrant.

     FORWARD-LOOKING STATEMENTS
              Except for the historical information contained herein, certain of
     the matters discussed in this Report are forward-looking statements, within
     the meaning of the Private Securities Litigation Reform Act of 1995, that
     are subject to risks and uncertainties. The factors that could cause actual
     results to differ materially from the forward-looking statements made by a
     registrant include those factors discussed herein, as well as the items
     discussed in (a) the Registrants' 2002 Annual Report on Form 10-K - ITEM 7.
     Management's Discussion and Analysis of Financial Condition and Results of
     Operations--Business Outlook and the Challenges in Managing Our Business
     for each of Exelon, ComEd, PECO and Generation, (b) the Registrants' 2002
     Annual Report on Form 10-K - ITEM 8. Financial Statements and Supplementary
     Data: Exelon - Note 19, ComEd - Note 16, PECO - Note 18 and Generation -
     Note 13 and (c) other factors discussed in filings with the United States
     Securities and Exchange Commission (SEC) by the Registrants. Readers are
     cautioned not to place undue reliance on these forward-looking statements,
     which apply only as of the date of this Report. None of the Registrants
     undertakes any obligation to publicly release any revision to its
     forward-looking statements to reflect events or circumstances after the
     date of this Report.

     WHERE TO FIND MORE INFORMATION
              The public may read and copy any reports or other information that
     the Registrants file with the SEC at the SEC's public reference room at 450
     Fifth Street, N.W., Washington, D.C. 20549. The public may obtain
     information on the operation of the Public Reference Room by calling the
     SEC at 1-800-SEC-0330. These documents are also available to the public
     from commercial document retrieval services, the web site maintained by the
     SEC at www.sec.gov and Exelon Corporation's website at www.exeloncorp.com.




                                       3
<PAGE>



                          PART I. FINANCIAL INFORMATION

                          ITEM 1. FINANCIAL STATEMENTS






                                       4
<PAGE>

<TABLE>
<CAPTION>

     EXELON CORPORATION
     ------------------


                                             EXELON CORPORATION AND SUBSIDIARY COMPANIES
                                     CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
                                                             (Unaudited)

                                                                  Three Months Ended June 30,    Six Months Ended June 30,
                                                                  ---------------------------    -------------------------
     (in millions, except per share data)                                   2003         2002         2003         2002
-------------------------------------------------------------------------------------------------------------------------

<S>                                                                    <C>            <C>         <C>           <C>
   OPERATING REVENUES                                                   $ 3,721      $ 3,519      $ 7,795      $ 6,876

   OPERATING EXPENSES
       Purchased power                                                      746          699        1,586        1,311
       Purchased power from unconsolidated affiliate                        110           60          177          116
       Fuel                                                                 531          364        1,356          860
       Operating and maintenance                                          1,100        1,070        2,212        2,137
       Depreciation and amortization                                        275          332          549          667
       Taxes other than income                                              159          181          358          367
-------------------------------------------------------------------------------------------------------------------------
            Total operating expenses                                      2,921        2,706        6,238        5,458
-------------------------------------------------------------------------------------------------------------------------
   OPERATING INCOME                                                         800          813        1,557        1,418
-------------------------------------------------------------------------------------------------------------------------
   OTHER INCOME AND DEDUCTIONS
       Interest expense                                                    (220)        (241)        (443)        (490)
       Distributions on preferred securities of subsidiaries                (10)         (11)         (22)         (23)
       Equity in earnings of unconsolidated affiliates                       15            9           33           22
       Other, net                                                             9          194         (134)         222
-------------------------------------------------------------------------------------------------------------------------
            Total other income and deductions                              (206)         (49)        (566)        (269)
-------------------------------------------------------------------------------------------------------------------------
   INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT
     OF CHANGES IN ACCOUNTING PRINCIPLES                                    594          764          991        1,149
   INCOME TAXES                                                             222          279          370          427
-------------------------------------------------------------------------------------------------------------------------
   INCOME BEFORE CUMULATIVE EFFECT OF CHANGES IN
     ACCOUNTING PRINCIPLES                                                  372          485          621          722
   CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING
     PRINCIPLES (net of income taxes of $69 and $(90) for the six
     months ended June 30, 2003 and 2002, respectively)                      --           --          112         (230)
-------------------------------------------------------------------------------------------------------------------------
   NET INCOME                                                               372          485          733          492
-------------------------------------------------------------------------------------------------------------------------
   OTHER COMPREHENSIVE INCOME (LOSS) (net of income taxes)
         Cash flow hedge adjustment                                          62          (16)         (84)         (68)
         Foreign currency translation adjustment                              1           --            2           --
         Unrealized gain (loss) on marketable securities                      3          (72)          (2)         (87)
         SFAS No. 143 transition adjustment                                  --           --           168          --
         Interest in other comprehensive income (loss) of unconsolidated
         affiliates                                                          17           (7)           8           (1)
-------------------------------------------------------------------------------------------------------------------------
            Total other comprehensive income (loss)                          83          (95)          92         (156)
-------------------------------------------------------------------------------------------------------------------------

   TOTAL COMPREHENSIVE INCOME                                           $   455      $   390      $   825      $   336
=========================================================================================================================

   AVERAGE SHARES OF COMMON STOCK OUTSTANDING - Basic                       325          322          324          322
=========================================================================================================================
   AVERAGE SHARES OF COMMON STOCK OUTSTANDING - Diluted                     327          324          327          324
=========================================================================================================================
   EARNINGS PER AVERAGE COMMON SHARE:
       BASIC:
       Income before cumulative effect of changes in accounting
       principles                                                       $  1.14      $  1.50      $  1.92      $  2.24
       Cumulative effect of changes in accounting principles                 --           --         0.34        (0.71)
-------------------------------------------------------------------------------------------------------------------------
       Net income                                                       $  1.14      $  1.50      $  2.26      $  1.53
-------------------------------------------------------------------------------------------------------------------------

       DILUTED:
       Income before cumulative effect of changes in accounting
       principles                                                       $  1.14      $  1.50      $  1.90      $  2.23
       Cumulative effect of changes in accounting principles                 --           --         0.34        (0.71)
-------------------------------------------------------------------------------------------------------------------------
       Net income                                                       $  1.14      $  1.50      $  2.24      $  1.52
=========================================================================================================================
   DIVIDENDS PER COMMON SHARE                                           $  0.46      $  0.44      $  0.92      $  0.88
=========================================================================================================================

</TABLE>

       See Condensed Combined Notes to Consolidated Financial Statements


                                       5
<PAGE>

<TABLE>
<CAPTION>


                   EXELON CORPORATION AND SUBSIDIARY COMPANIES
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                                   (Unaudited)

                                                                                              Six Months Ended June 30,
                                                                                              -------------------------
     (in millions)                                                                               2003              2002
-----------------------------------------------------------------------------------------------------------------------
     CASH FLOWS FROM OPERATING ACTIVITIES
<S>                                                                                          <C>                <C>
         Net income                                                                          $    733           $   492
         Adjustments to reconcile net income to net cash flows provided by
           operating activities:
              Depreciation, amortization and accretion, including nuclear fuel                    846               848
              Cumulative effect of changes in accounting principles (net of income taxes)        (112)              230
              Gain on sale of investments                                                          --              (199)
              Provision for uncollectible accounts                                                 43                67
              Deferred income taxes                                                              (100)              (10)
              Equity in earnings of unconsolidated affiliates                                     (33)              (22)
              Impairment of investments                                                           238                38
              Impairment of goodwill and long-lived assets                                         53                --
              Net realized (gains) losses on nuclear decommissioning trust funds                  (12)               21
              Other operating activities                                                           12                40
              Changes in assets and liabilities:
                Accounts receivable                                                                66              (281)
                Inventories                                                                       (16)               (3)
                Accounts payable, accrued expenses and other current liabilities                  (62)              364
                Changes in payables and receivables from unconsolidated affiliates                 19                12
                Other current assets                                                             (214)             (143)
                Deferred energy costs                                                             (24)               49
                Pension and non-pension postretirement benefits obligations                      (146)               10
                Other noncurrent assets and liabilities                                             1               125
-----------------------------------------------------------------------------------------------------------------------
     Net cash flows provided by operating activities                                            1,292             1,638
-----------------------------------------------------------------------------------------------------------------------

     CASH FLOWS FROM INVESTING ACTIVITIES
         Capital expenditures                                                                  (1,019)           (1,028)
         Proceeds from liquidated damages                                                          86                --
         Proceeds from nuclear decommissioning trust funds                                      1,262               889
         Investment in nuclear decommissioning trust funds                                     (1,368)             (943)
         Note receivable from unconsolidated affiliate                                             35               (75)
         Proceeds from sale of investment                                                           6               285
         Acquisition of generating plants                                                          --              (443)
         Other investing activities                                                                11                47
-----------------------------------------------------------------------------------------------------------------------
     Net cash flows used in investing activities                                                 (987)           (1,268)
-----------------------------------------------------------------------------------------------------------------------

     CASH FLOWS FROM FINANCING ACTIVITIES
         Issuance of long-term debt                                                             1,813               701
         Retirement of long-term debt                                                          (1,479)             (697)
         Change in short-term debt                                                               (100)              110
         Issuance of preferred securities of subsidiaries                                         300                --
         Retirement of preferred securities of subsidiaries                                      (300)               --
         Dividends paid on common stock                                                          (285)             (280)
         Payment on acquisition note payable to Sithe Energies, Inc.                             (210)               --
         Proceeds from employee stock plans                                                        91                60
         Change in restricted cash                                                                (29)              (26)
         Other financing activities                                                               (85)              (10)
-----------------------------------------------------------------------------------------------------------------------
     Net cash flows used in financing activities                                                 (284)             (142)
-----------------------------------------------------------------------------------------------------------------------

     INCREASE IN CASH AND CASH EQUIVALENTS                                                         21               228

     CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD                                             469               485
-----------------------------------------------------------------------------------------------------------------------

     CASH AND CASH EQUIVALENTS INCLUDING CASH CLASSIFIED AS HELD FOR SALE                         490               713
     CASH CLASSIFIED AS HELD FOR SALE ON THE CONSOLIDATED BALANCE SHEET                           (26)               --
-----------------------------------------------------------------------------------------------------------------------
     CASH AND CASH EQUIVALENTS AT END OF PERIOD                                            $      464        $      713
-----------------------------------------------------------------------------------------------------------------------

        See Condensed Combined Notes to Consolidated Financial Statements


                                       6
<PAGE>


</TABLE>



<TABLE>
<CAPTION>

                   EXELON CORPORATION AND SUBSIDIARY COMPANIES
                           CONSOLIDATED BALANCE SHEETS
                                   (Unaudited)


                                                                                                June 30,      December 31,
     (in millions)                                                                               2003              2002
-----------------------------------------------------------------------------------------------------------------------
     ASSETS

     CURRENT ASSETS
<S>                                                                                          <C>                <C>
         Cash and cash equivalents                                                           $    464        $      469
         Restricted cash                                                                          425               396
         Accounts receivable, net
              Customer                                                                          1,903             2,076
              Other                                                                               246               284
         Receivable from unconsolidated affiliate                                                  --                39
         Inventories, at average cost
              Fossil fuel                                                                         172               175
              Materials and supplies                                                              309               306
         Other                                                                                    579               380
         Assets held for sale                                                                     352                --
-----------------------------------------------------------------------------------------------------------------------
              Total current assets                                                              4,450             4,125
-----------------------------------------------------------------------------------------------------------------------

     PROPERTY, PLANT AND EQUIPMENT, NET                                                        20,323            17,126

     DEFERRED DEBITS AND OTHER ASSETS
         Regulatory assets                                                                      5,414             5,993
         Nuclear decommissioning trust funds                                                    3,316             3,053
         Investments                                                                            1,189             1,403
         Goodwill                                                                               4,735             4,992
         Other                                                                                    861               793
-----------------------------------------------------------------------------------------------------------------------
              Total deferred debits and other assets                                           15,515            16,234
-----------------------------------------------------------------------------------------------------------------------

     TOTAL ASSETS                                                                            $ 40,288        $   37,485
=======================================================================================================================

</TABLE>


        See Condensed Combined Notes to Consolidated Financial Statements


                                       7
<PAGE>


                   EXELON CORPORATION AND SUBSIDIARY COMPANIES
                           CONSOLIDATED BALANCE SHEETS
                                   (Unaudited)
<TABLE>
<CAPTION>


                                                                                                June 30,      December 31,
     (in millions)                                                                               2003              2002
-----------------------------------------------------------------------------------------------------------------------
     LIABILITIES AND SHAREHOLDERS' EQUITY

     CURRENT LIABILITIES
<S>                                                                                          <C>                <C>
         Notes payable                                                                       $    581           $   681
         Note payable to unconsolidated affiliate                                                 326               534
         Long-term debt due within one year                                                     2,391             1,402
         Accounts payable                                                                       1,762             1,607
         Accrued expenses                                                                       1,205             1,354
         Other                                                                                    283               296
         Liabilities held for sale                                                                 81                --
-----------------------------------------------------------------------------------------------------------------------
              Total current liabilities                                                         6,629             5,874
-----------------------------------------------------------------------------------------------------------------------

     LONG-TERM DEBT                                                                            12,480            13,127

     MANDATORILY REDEEMABLE PREFERRED SECURITIES                                                  100                --

     DEFERRED CREDITS AND OTHER LIABILITIES
         Deferred income taxes                                                                  3,973             3,702
         Unamortized investment tax credits                                                       295               301
         Nuclear decommissioning liability for retired plants                                      --             1,395
         Asset retirement obligation                                                            2,444                --
         Pension obligation                                                                     1,747             1,959
         Non-pension postretirement benefits obligation                                           943               877
         Spent nuclear fuel obligation                                                            863               858
         Regulatory liabilities                                                                   810                --
         Other                                                                                  1,037               978
-----------------------------------------------------------------------------------------------------------------------
              Total deferred credits and other liabilities                                     12,112            10,070
-----------------------------------------------------------------------------------------------------------------------

     COMMITMENTS AND CONTINGENCIES

     MINORITY INTEREST OF CONSOLIDATED SUBSIDIARIES                                                79                77

     PREFERRED SECURITIES OF SUBSIDIARIES                                                         510               595

     SHAREHOLDERS' EQUITY
         Common stock                                                                           7,169             7,059
         Deferred compensation                                                                     --                (1)
         Retained earnings                                                                      2,475             2,042
         Accumulated other comprehensive income (loss)                                         (1,266)           (1,358)
-----------------------------------------------------------------------------------------------------------------------
              Total shareholders' equity                                                        8,378             7,742
-----------------------------------------------------------------------------------------------------------------------

     TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY                                              $ 40,288        $   37,485
=======================================================================================================================


                        See Condensed Combined Notes to Consolidated Financial Statements

</TABLE>


                                       8
<PAGE>



     COMMONWEALTH EDISON COMPANY
     ---------------------------
<TABLE>
<CAPTION>
                                        COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
                                     CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
                                                             (Unaudited)



                                                                     Three Months Ended June 30,  Six Months Ended June 30,
                                                                     --------------------------   -------------------------
     (in millions)                                                          2003         2002         2003         2002
---------------------------------------------------------------------------------------------------------------------------
     OPERATING REVENUES
<S>                                                                    <C>            <C>          <C>          <C>
         Operating revenues                                            $   1,345      $ 1,469      $ 2,756      $ 2,773
         Operating revenues from affiliates                                   16           12           29           23
---------------------------------------------------------------------------------------------------------------------------
              Total operating revenues                                     1,361        1,481        2,785        2,796
---------------------------------------------------------------------------------------------------------------------------

     OPERATING EXPENSES
         Purchased power                                                       5            6           11           12
         Purchased power from affiliate                                      528          547        1,099        1,079
         Operating and maintenance                                           193          191          425          386
         Operating and maintenance from affiliates                            28           29           58           71
         Depreciation and amortization                                        96          133          190          268
         Taxes other than income                                              68           73          148          146
---------------------------------------------------------------------------------------------------------------------------
              Total operating expenses                                       918          979        1,931        1,962
---------------------------------------------------------------------------------------------------------------------------

     OPERATING INCOME                                                        443          502          854          834
---------------------------------------------------------------------------------------------------------------------------

     OTHER INCOME AND DEDUCTIONS
         Interest expense                                                   (106)        (127)        (215)        (252)
         Distributions on mandatorily redeemable preferred securities         (6)          (7)         (14)         (15)
         Interest income from affiliates                                       7            8           13           16
         Other, net                                                            5            6           21           13
---------------------------------------------------------------------------------------------------------------------------
              Total other income and deductions                             (100)        (120)        (195)        (238)
---------------------------------------------------------------------------------------------------------------------------

     INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT
       OF A CHANGE IN ACCOUNTING PRINCIPLE                                   343          382          659          596
     INCOME TAXES                                                            138          151          263          236
---------------------------------------------------------------------------------------------------------------------------

     INCOME BEFORE CUMULATIVE EFFECT OF A CHANGE IN
       ACCOUNTING  PRINCIPLE                                                 205          231          396          360

     CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING
       PRINCIPLE (net of income taxes of $0)                                  --           --            5           --
---------------------------------------------------------------------------------------------------------------------------
     NET INCOME                                                              205          231          401          360
---------------------------------------------------------------------------------------------------------------------------

     OTHER COMPREHENSIVE INCOME (LOSS) (net of income taxes)
             Cash flow hedge adjustment                                       (3)          (9)          28           (6)
           Unrealized gain (loss) on marketable securities                     1           (2)           1           (2)
           Foreign currency translation adjustment                             1           --            2           --
---------------------------------------------------------------------------------------------------------------------------
              Total other comprehensive income (loss)                         (1)         (11)          31           (8)
---------------------------------------------------------------------------------------------------------------------------

     TOTAL COMPREHENSIVE INCOME                                        $     204      $   220      $   432        $ 352
===========================================================================================================================


        See Condensed Combined Notes to Consolidated Financial Statements


                                       9
<PAGE>



              COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                                   (Unaudited)

                                                                                              Six Months Ended June 30,
                                                                                              -------------------------
     (in millions)                                                                               2003              2002
-------------------------------------------------------------------------------------------------------------------------
     CASH FLOWS FROM OPERATING ACTIVITIES
         Net income                                                                          $    401           $   360
         Adjustments to reconcile net income to net cash flows provided by
           operating activities:
              Depreciation and amortization                                                       190               268
              Cumulative effect of a change in accounting principle (net of income taxes)          (5)               --
              Provision for uncollectible accounts                                                 20                11
              Deferred income taxes                                                                60                75
              Other operating activities                                                           25                29
              Changes in assets and liabilities:
                Accounts receivable                                                                 9              (158)
                Inventories                                                                         2                --
                Accounts payable, accrued expenses and other current liabilities                 (115)               51
                Changes in receivables and payables to affiliates                                 (94)               63
                Other current assets                                                               (2)               (1)
                Pension and non-pension postretirement benefits obligations                       (72)               15
                Other noncurrent assets and liabilities                                            11                27
-------------------------------------------------------------------------------------------------------------------------
     Net cash flows provided by operating activities                                              430               740
-------------------------------------------------------------------------------------------------------------------------

     CASH FLOWS FROM INVESTING ACTIVITIES
         Capital expenditures                                                                    (355)             (372)
         Notes receivable from affiliates                                                        (165)               13
         Other investing activities                                                                14                 7
-------------------------------------------------------------------------------------------------------------------------
     Net cash flows used in investing activities                                                 (506)             (352)
-------------------------------------------------------------------------------------------------------------------------

     CASH FLOWS FROM FINANCING ACTIVITIES
         Issuance of long-term debt                                                             1,135               701
         Retirement of long-term debt                                                            (662)             (481)
         Issuance of mandatorily redeemable preferred securities                                  200                --
         Retirement of mandatorily redeemable preferred securities                               (200)               --
         Change in short-term debt                                                                (71)               --
         Dividends paid on common stock                                                          (211)             (235)
         Change in restricted cash                                                                (18)              (32)
         Settlement of cash flow hedges                                                           (51)              (10)
         Other financing activities                                                               (28)               --
-------------------------------------------------------------------------------------------------------------------------
     Net cash flows provided by (used in) financing activities                                     94               (57)
---------------------------------------------------------------------------------------------------------------------------


     INCREASE IN CASH AND CASH EQUIVALENTS                                                         18               331


     CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD                                              16                23
-------------------------------------------------------------------------------------------------------------------------


     CASH AND CASH EQUIVALENTS AT END OF PERIOD                                              $     34           $   354
=========================================================================================================================

     SUPPLEMENTAL CASH FLOW INFORMATION
     Noncash investing and financing activities:
         Retirement of treasury shares                                                       $     --         $   1,344
         Adoption of SFAS No. 143 - adjustment to other paid in capital and goodwill              210                --



        See Condensed Combined Notes to Consolidated Financial Statements
</TABLE>

                                       10

<PAGE>


<TABLE>
<CAPTION>

              COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
                           CONSOLIDATED BALANCE SHEETS
                                   (Unaudited)



                                                                                             June 30,      December 31,
     (in millions)                                                                               2003              2002
-------------------------------------------------------------------------------------------------------------------------
     ASSETS

     CURRENT ASSETS
<S>                                                                                          <C>                 <C>
         Cash and cash equivalents                                                           $     34        $       16
         Restricted cash                                                                           83                65
         Accounts receivable, net
              Customer                                                                            747               782
              Other                                                                                78                72
         Inventories, at average cost                                                              63                65
         Deferred income taxes                                                                     19                20
         Receivables from affiliates                                                              177                15
         Other                                                                                     16                14
-------------------------------------------------------------------------------------------------------------------------
              Total current assets                                                               1,217            1,049
-------------------------------------------------------------------------------------------------------------------------

     PROPERTY, PLANT AND EQUIPMENT, NET                                                         7,944             7,756

     DEFERRED DEBITS AND OTHER ASSETS
         Regulatory assets                                                                         --               447
         Investments                                                                               35                42
         Goodwill                                                                               4,711             4,916
         Receivables from affiliates                                                            2,397             1,300
         Other                                                                                    373               320
-------------------------------------------------------------------------------------------------------------------------
         Total deferred debits and other assets                                                  7,516            7,025
-------------------------------------------------------------------------------------------------------------------------

     TOTAL ASSETS                                                                            $ 16,677        $   15,830
=========================================================================================================================


</TABLE>

        See Condensed Combined Notes to Consolidated Financial Statements


                                       11
<PAGE>


<TABLE>
<CAPTION>


              COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
                           CONSOLIDATED BALANCE SHEETS
                                   (Unaudited)


                                                                                             June 30,      December 31,
     (in millions)                                                                               2003              2002
-------------------------------------------------------------------------------------------------------------------------
     LIABILITIES AND SHAREHOLDERS' EQUITY

     CURRENT LIABILITIES
<S>                                                                                          <C>              <C>
         Notes payable                                                                       $     --         $      71
         Long-term debt due within one year                                                       869               698
         Accounts payable                                                                         158               201
         Accrued expenses                                                                         456               538
         Payables to affiliates                                                                   209               416
         Customer deposits                                                                         79                81
         Other                                                                                     19                18
-------------------------------------------------------------------------------------------------------------------------
              Total current liabilities                                                         1,790             2,023
-------------------------------------------------------------------------------------------------------------------------

     LONG-TERM DEBT                                                                             5,584             5,268

     DEFERRED CREDITS AND OTHER LIABILITIES
          Deferred income taxes                                                                 1,741             1,650
          Unamortized investment tax credits                                                       50                51
          Pension obligation                                                                        1                91
          Non-pension postretirement benefits obligation                                          156               138
          Payables to affiliates                                                                   26               224
          Regulatory liabilities                                                                  810                --
          Other                                                                                   345               297
-------------------------------------------------------------------------------------------------------------------------
              Total deferred credits and other liabilities                                      3,129             2,451
-------------------------------------------------------------------------------------------------------------------------

     COMMITMENTS AND CONTINGENCIES

     MANDATORILY REDEEMABLE PREFERRED SECURITIES                                                  344               330

     SHAREHOLDERS' EQUITY
         Common stock                                                                           1,588             1,588
         Preference stock                                                                           7                 7
         Other paid in capital                                                                  4,029             4,239
         Receivable from parent                                                                  (554)             (615)
         Retained earnings                                                                        767               577
         Accumulated other comprehensive income (loss)                                             (7)              (38)
-------------------------------------------------------------------------------------------------------------------------
              Total shareholders' equity                                                        5,830             5,758
-------------------------------------------------------------------------------------------------------------------------

     TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY                                              $ 16,677        $   15,830
=========================================================================================================================

</TABLE>

        See Condensed Combined Notes to Consolidated Financial Statements



                                       12
<PAGE>


<TABLE>
<CAPTION>


     PECO ENERGY COMPANY
     -------------------
                                        PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
                                   CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
                                                            (Unaudited)


                                                                  Three Months Ended June 30,  Six Months Ended June 30,
                                                                  ---------------------------  ------------------------
     (in millions)                                                    2003         2002         2003         2002
-----------------------------------------------------------------------------------------------------------------------
   OPERATING REVENUES
<S>                                                                <C>          <C>          <C>          <C>
       Operating revenues                                          $   958      $   992      $ 2,173      $ 2,008
       Operating revenues from affiliates                                3            3            5            7
-----------------------------------------------------------------------------------------------------------------------
            Total operating revenues                                   961          995        2,178        2,015
-----------------------------------------------------------------------------------------------------------------------

   OPERATING EXPENSES
       Purchased power                                                  62           59          127          107
       Purchased power from affiliate                                  324          346          681          649
       Fuel                                                             67           53          257          188
       Operating and maintenance                                       110          114          236          225
       Operating and maintenance from affiliates                        11           17           25           42
       Depreciation and amortization                                   116          109          236          221
       Taxes other than income                                          47           63          110          122
-----------------------------------------------------------------------------------------------------------------------
            Total operating expenses                                   737          761        1,672        1,554
-----------------------------------------------------------------------------------------------------------------------

   OPERATING INCOME                                                    224          234          506          461
-----------------------------------------------------------------------------------------------------------------------

   OTHER INCOME AND DEDUCTIONS
       Interest expense                                                (83)         (92)        (168)        (187)
       Distributions on mandatorily redeemable preferred securities     (2)          (2)          (5)          (5)
       Other, net                                                        1            2           10            2
-----------------------------------------------------------------------------------------------------------------------
            Total other income and deductions                          (84)         (92)        (163)        (190)
-----------------------------------------------------------------------------------------------------------------------

   INCOME BEFORE INCOME TAXES                                          140          142          343          271
   INCOME TAXES                                                         52           49          119           90
-----------------------------------------------------------------------------------------------------------------------
   NET INCOME                                                           88           93          224          181
       Preferred stock dividends                                        (2)          (2)          (3)          (4)
-----------------------------------------------------------------------------------------------------------------------
   NET INCOME ON COMMON STOCK                                      $    86      $    91      $   221      $   177
=======================================================================================================================


   OTHER COMPREHENSIVE INCOME (LOSS)  (net of income taxes)
       Net income                                                  $    88      $    93      $   224      $   181
       Other comprehensive income (loss) (net of income taxes):
         Cash flow hedge adjustment                                   --             (6)        --             (4)
-----------------------------------------------------------------------------------------------------------------------
            Total other comprehensive income (loss)                   --             (6)        --             (4)
-----------------------------------------------------------------------------------------------------------------------

   TOTAL COMPREHENSIVE INCOME                                      $    88      $    87      $   224      $   177
=======================================================================================================================

        See Condensed Combined Notes to Consolidated Financial Statements

</TABLE>

                                       13
<PAGE>

<TABLE>
<CAPTION>


                  PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                                   (Unaudited)

                                                                                              Six Months Ended June 30,
                                                                                              -------------------------
     (in millions)                                                                               2003              2002
-----------------------------------------------------------------------------------------------------------------------
     CASH FLOWS FROM OPERATING ACTIVITIES
<S>                                                                                          <C>                <C>
         Net income                                                                          $    224           $   181
         Adjustments to reconcile net income to net cash flows provided by
           operating activities:
              Depreciation and amortization                                                       236               221
              Provision for uncollectible accounts                                                 21                32
              Deferred income taxes                                                               (28)              (19)
              Other operating activities                                                            5                --
              Changes in assets and liabilities:
                Accounts receivable                                                                48                (4)
                Changes in receivables and payables to affiliates                                  27                34
                Inventories                                                                        (1)               14
                Accounts payable, accrued expenses and other current liabilities                   11                44
                Prepaid taxes                                                                     (91)              (98)
                Deferred energy costs                                                             (24)               49
                Other current assets                                                               (4)               (3)
                Pension and non-pension postretirement benefits obligations                        16                 8
                Other noncurrent assets and liabilities                                           (15)                9
-----------------------------------------------------------------------------------------------------------------------
     Net cash flows provided by operating activities                                              425               468
-----------------------------------------------------------------------------------------------------------------------


     CASH FLOWS FROM INVESTING ACTIVITIES
         Capital expenditures                                                                    (132)             (132)
         Other investing activities                                                                 6                10
-----------------------------------------------------------------------------------------------------------------------
     Net cash flows used in investing activities                                                 (126)             (122)
-----------------------------------------------------------------------------------------------------------------------


     CASH FLOWS FROM FINANCING ACTIVITIES
         Issuance of long-term debt                                                               450                --
         Issuance of mandatorily redeemable preferred securities                                  100                --
         Retirement of long-term debt                                                            (592)             (207)
         Retirement of mandatorily redeemable preferred securities                                (50)               --
         Retirement of preferred stock                                                            (50)               --
         Change in short-term debt                                                                (30)               74
         Dividends paid on preferred and common stock                                            (168)             (174)
         Contribution from parent                                                                  17                --
         Change in restricted cash                                                                 28                 1
         Other financing activities                                                                (6)               --
-----------------------------------------------------------------------------------------------------------------------
     Net cash flows used in financing activities                                                 (301)             (306)
-----------------------------------------------------------------------------------------------------------------------


     INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS                                              (2)               40


     CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD                                              63                32
-----------------------------------------------------------------------------------------------------------------------


     CASH AND CASH EQUIVALENTS AT END OF PERIOD                                               $    61            $   72
=======================================================================================================================


        See Condensed Combined Notes to Consolidated Financial Statements

</TABLE>

                                       14
<PAGE>
<TABLE>
<CAPTION>


                                       PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
                                               CONSOLIDATED BALANCE SHEETS
                                                       (Unaudited)


                                                                                             June 30,      December 31,
     (in millions)                                                                               2003              2002
-----------------------------------------------------------------------------------------------------------------------
     ASSETS

     CURRENT ASSETS
<S>                                                                                          <C>
         Cash and cash equivalents                                                           $     61            $   63
         Restricted cash                                                                          303               331
         Accounts receivable, net
              Customer                                                                            300               379
              Other                                                                                51                39
         Inventories, at average cost
              Fossil fuel                                                                          67                67
              Materials and supplies                                                                9                 8
         Deferred energy costs                                                                     55                31
         Prepaid taxes                                                                             92                 1
         Other                                                                                     10                 8
-----------------------------------------------------------------------------------------------------------------------
              Total current assets                                                                 948              927
-----------------------------------------------------------------------------------------------------------------------

     PROPERTY, PLANT AND EQUIPMENT, NET                                                         4,213             4,159

     DEFERRED DEBITS AND OTHER ASSETS
         Regulatory assets                                                                      5,414             5,546
         Investments                                                                               19                19
         Prepaid pension asset                                                                     56                41
         Other                                                                                     22                28
-----------------------------------------------------------------------------------------------------------------------
              Total deferred debits and other assets                                            5,511             5,634
-----------------------------------------------------------------------------------------------------------------------

     TOTAL ASSETS                                                                            $ 10,672        $   10,720
=======================================================================================================================


        See Condensed Combined Notes to Consolidated Financial Statements

</TABLE>

                                       15
<PAGE>


<TABLE>
<CAPTION>



                  PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
                           CONSOLIDATED BALANCE SHEETS
                                   (Unaudited)



                                                                                             June 30,      December 31,
     (in millions)                                                                             2003            2002
-----------------------------------------------------------------------------------------------------------------------
     LIABILITIES AND SHAREHOLDERS' EQUITY

     CURRENT LIABILITIES
<S>                                                                                          <C>                <C>
         Notes payable                                                                       $    170           $   200
         Payables to affiliates                                                                   137               170
         Long-term debt due within one year                                                       264               689
         Accounts payable                                                                          70                87
         Accrued expenses                                                                         361               332
         Deferred income taxes                                                                     27                27
         Other                                                                                     32                33
-----------------------------------------------------------------------------------------------------------------------
              Total current liabilities                                                         1,061             1,538
-----------------------------------------------------------------------------------------------------------------------

     LONG-TERM DEBT                                                                             5,230             4,951

     MANDATORILY REDEEMABLE PREFERRED SECURITIES                                                  100                --

     DEFERRED CREDITS AND OTHER LIABILITIES
         Deferred income taxes                                                                  2,891             2,903
         Unamortized investment tax credits                                                        23                24
         Non-pension postretirement benefits obligation                                           282               251
         Payable to affiliate                                                                      16                --
         Other                                                                                    149               164
-----------------------------------------------------------------------------------------------------------------------
              Total deferred credits and other liabilities                                      3,361             3,342
-----------------------------------------------------------------------------------------------------------------------

     COMMITMENTS AND CONTINGENCIES

     MANDATORILY REDEEMABLE PREFERRED SECURITIES                                                   78               128

     SHAREHOLDERS' EQUITY
         Common stock                                                                           1,993             1,976
         Receivable from parent                                                                (1,698)           (1,758)
         Preferred stock                                                                           87               137
         Retained earnings                                                                        455               401
         Accumulated other comprehensive income                                                     5                 5
-----------------------------------------------------------------------------------------------------------------------
              Total shareholders' equity                                                          842               761
-----------------------------------------------------------------------------------------------------------------------

     TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY                                              $ 10,672        $   10,720
=======================================================================================================================

</TABLE>

        See Condensed Combined Notes to Consolidated Financial Statements


                                       16
<PAGE>


<TABLE>
<CAPTION>


EXELON GENERATION COMPANY, LLC
------------------------------

             EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
           CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
                                   (Unaudited)


                                                                      Three Months Ended June 30,    Six Months Ended June 30,
                                                                      ---------------------------    --------------------------
     (in millions)                                                          2003         2002         2003         2002
------------------------------------------------------------------------------------------------------------------------
     OPERATING REVENUES
<S>                                                                    <C>            <C>          <C>          <C>
         Operating revenues                                            $     990      $   606      $ 1,876      $ 1,175
         Operating revenues from affiliates                                  896          953        1,889        1,845
------------------------------------------------------------------------------------------------------------------------
              Total operating revenues                                     1,886        1,559        3,765        3,020
------------------------------------------------------------------------------------------------------------------------

     OPERATING EXPENSES
         Purchased power                                                     675          634        1,436        1,186
         Purchased power from affiliates                                     125           71          206          137
         Fuel                                                                348          224          706          433
         Operating and maintenance                                           411          374          861          750
         Operating and maintenance from affiliates                            40           37           82           94
         Depreciation and amortization                                        46           65           91          128
         Taxes other than income                                              40           41           88           90
------------------------------------------------------------------------------------------------------------------------
              Total operating expenses                                     1,685        1,446        3,470        2,818
------------------------------------------------------------------------------------------------------------------------

     OPERATING INCOME                                                        201          113          295          202
------------------------------------------------------------------------------------------------------------------------

     OTHER INCOME AND DEDUCTIONS
         Interest expense                                                    (16)         (10)         (30)         (27)
         Interest expense - affiliates                                        (4)          (1)          (8)          (1)
         Equity in earnings of unconsolidated affiliates                      18            9           37           32
         Other, net                                                           34           24         (134)          40
------------------------------------------------------------------------------------------------------------------------
              Total other income and deductions                               32           22         (135)          44
------------------------------------------------------------------------------------------------------------------------

     INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT
       OF CHANGES IN ACCOUNTING PRINCIPLES                                   233          135          160          246

     INCOME TAXES                                                             91           51           71           96
------------------------------------------------------------------------------------------------------------------------
     INCOME BEFORE CUMULATIVE EFFECT OF CHANGES IN
       ACCOUNTING PRINCIPLES                                                 142           84           89          150

     CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING
       PRINCIPLES (net of income taxes of $70 and $9 for the six
        months ended June 30, 2003 and 2002, respectively)                    --           --          108           13
------------------------------------------------------------------------------------------------------------------------
     NET INCOME                                                              142           84          197          163
------------------------------------------------------------------------------------------------------------------------

       OTHER COMPREHENSIVE INCOME (LOSS) (net of income taxes)
           Unrealized gain (loss) on marketable securities                     2          (74)          (3)         (83)
           SFAS No. 143 transition adjustment                                 --           --          168           --
           Cash flow hedge adjustment                                         64            6         (116)         (67)
           Interest in other comprehensive income (loss) of unconsolidated
           affiliates                                                         17           (7)           8           (1)
------------------------------------------------------------------------------------------------------------------------
              Total other comprehensive income (loss)                         83          (75)          57         (151)
------------------------------------------------------------------------------------------------------------------------

     TOTAL COMPREHENSIVE INCOME                                        $     225      $     9      $   254      $   12
========================================================================================================================

        See Condensed Combined Notes to Consolidated Financial Statements

</TABLE>


                                       17
<PAGE>

<TABLE>
<CAPTION>

                                 EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
                                          CONSOLIDATED STATEMENTS OF CASH FLOWS
                                                       (Unaudited)

                                                                                              Six Months Ended June 30,
                                                                                              -------------------------
     (in millions)                                                                               2003              2002
------------------------------------------------------------------------------------------------------------------------
     CASH FLOWS FROM OPERATING ACTIVITIES
<S>                                                                                          <C>                <C>
         Net income                                                                          $    197           $   163
         Adjustments to reconcile net income to net cash flows provided by
           operating activities:
              Depreciation, amortization and accretion, including nuclear fuel                    388               312
              Cumulative effect of changes in accounting principles (net of income taxes)        (108)              (13)
              Provision for uncollectible accounts                                                  1                17
              Deferred income taxes                                                              (107)               (4)
              Equity in earnings of unconsolidated affiliates                                     (37)              (32)
              Impairment of investment                                                            200                --
              Impairment of long-lived assets                                                       5                --
              Net realized (gains) losses on nuclear decommissioning trust funds                  (12)               21
              Other operating activities                                                          (39)               53
              Changes in assets and liabilities:
                Accounts receivable                                                              (116)             (136)
                Changes in receivables and payables to affiliates, net                            238               (93)
                Inventories                                                                       (19)              (15)
                Accounts payable, accrued expenses and other current liabilities                   91               307
                Other current assets                                                             (104)              (87)
                Pension and non-pension postretirement benefits obligations                       (59)               (4)
                Other noncurrent assets and liabilities                                            20                30
------------------------------------------------------------------------------------------------------------------------
     Net cash flows provided by operating activities                                              539               519
------------------------------------------------------------------------------------------------------------------------

     CASH FLOWS FROM INVESTING ACTIVITIES
         Capital expenditures                                                                    (510)             (475)
         Proceeds from liquidated damages                                                          86                --
         Proceeds from nuclear decommissioning trust funds                                      1,262               889
         Investment in nuclear decommissioning trust funds                                     (1,368)             (943)
         Note receivable from unconsolidated affiliate                                             35               (75)
         Acquisition of generating plants                                                          --              (443)
         Other investing activities                                                                (1)               (1)
------------------------------------------------------------------------------------------------------------------------
     Net cash flows used in investing activities                                                 (496)           (1,048)
------------------------------------------------------------------------------------------------------------------------

     CASH FLOWS FROM FINANCING ACTIVITIES
         Issuance of long-term debt                                                               211                --
         Retirement of long-term debt                                                              (3)               (2)
         Payment on acquisition note payable to Sithe Energies, Inc.                             (210)               --
         Change in payables to affiliates                                                          58               331
         Distribution to member                                                                   (45)               --
         Change in restricted cash                                                                (38)               --
------------------------------------------------------------------------------------------------------------------------
     Net cash flows (used in) provided by financing activities                                    (27)              329
------------------------------------------------------------------------------------------------------------------------

     INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS                                              16              (200)

     CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD                                              58               224
------------------------------------------------------------------------------------------------------------------------

     CASH AND CASH EQUIVALENTS AT END OF PERIOD                                               $    74            $   24
========================================================================================================================

     SUPPLEMENTAL CASH FLOW INFORMATION
     Noncash financing activities:
         Distribution to member                                                               $    17            $   --

</TABLE>


        See Condensed Combined Notes to Consolidated Financial Statements



                                       18
<PAGE>

<TABLE>
<CAPTION>

                                 EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
                                               CONSOLIDATED BALANCE SHEETS
                                                       (Unaudited)


                                                                                               June 30,      December 31,
     (in millions)                                                                              2003              2002
------------------------------------------------------------------------------------------------------------------------
     ASSETS

     CURRENT ASSETS
<S>                                                                                          <C>                 <C>
         Cash and cash equivalents                                                           $     74         $      58
         Restricted cash                                                                           38                --
         Accounts receivable, net
              Customer                                                                            656               587
              Other                                                                                83                57
         Receivables from affiliates                                                              334               594
         Inventories, at average cost
              Fossil fuel                                                                          96                97
              Materials and supplies                                                              235               217
         Deferred income taxes                                                                      7                 7
         Other                                                                                    288               188
------------------------------------------------------------------------------------------------------------------------
              Total current assets                                                              1,811             1,805
------------------------------------------------------------------------------------------------------------------------

     PROPERTY, PLANT AND EQUIPMENT, NET                                                         7,884             4,800

     DEFERRED DEBITS AND OTHER ASSETS
         Nuclear decommissioning trust funds                                                    3,316             3,053
         Investments                                                                              484               657
         Receivable from affiliate                                                                 35               220
         Deferred income taxes                                                                    102               271
         Prepaid pension asset                                                                     55                --
         Other                                                                                    226               201
------------------------------------------------------------------------------------------------------------------------
              Total deferred debits and other assets                                            4,218             4,402
------------------------------------------------------------------------------------------------------------------------

     TOTAL ASSETS                                                                            $ 13,913         $  11,007
========================================================================================================================

</TABLE>


        See Condensed Combined Notes to Consolidated Financial Statements


                                       19
<PAGE>

<TABLE>
<CAPTION>

                                 EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
                                               CONSOLIDATED BALANCE SHEETS
                                                       (Unaudited)



                                                                                              June 30,      December 31,
     (in millions)                                                                             2003              2002
------------------------------------------------------------------------------------------------------------------------
     LIABILITIES AND MEMBER'S EQUITY

     CURRENT LIABILITIES
<S>                                                                                          <C>                  <C>
         Long-term debt due within one year                                                  $  1,252        $        5
         Accounts payable                                                                       1,408             1,126
         Payables to affiliates                                                                    45                10
         Notes payable to affiliates                                                              717               863
         Accrued expenses                                                                         431               482
         Other                                                                                     93               108
------------------------------------------------------------------------------------------------------------------------
              Total current liabilities                                                         3,946             2,594
------------------------------------------------------------------------------------------------------------------------

     LONG-TERM DEBT                                                                             1,111             2,132

     DEFERRED CREDITS AND OTHER LIABILITIES
         Unamortized investment tax credits                                                       222               226
         Nuclear decommissioning liability for retired plants                                      --             1,395
         Asset retirement obligation                                                            2,440                --
         Pension obligation                                                                        --                37
         Non-pension postretirement benefits obligation                                           443               410
         Spent nuclear fuel obligation                                                            863               858
         Payable to affiliate                                                                   1,094                --
         Other                                                                                    438               402
------------------------------------------------------------------------------------------------------------------------
              Total deferred credits and other liabilities                                      5,500             3,328
------------------------------------------------------------------------------------------------------------------------

     COMMITMENTS AND CONTINGENCIES

     MINORITY INTEREST OF CONSOLIDATED SUBSIDIARY                                                  54                54

     MEMBER'S EQUITY
         Membership interest                                                                    2,489             2,296
         Undistributed earnings                                                                 1,077               924
         Accumulated other comprehensive income (loss)                                           (264)             (321)
------------------------------------------------------------------------------------------------------------------------
              Total member's equity                                                             3,302             2,899
------------------------------------------------------------------------------------------------------------------------
     TOTAL LIABILITIES AND MEMBER'S EQUITY                                                  $  13,913        $   11,007
========================================================================================================================
</TABLE>


        See Condensed Combined Notes to Consolidated Financial Statements


                                       20
<PAGE>


                   EXELON CORPORATION AND SUBSIDIARY COMPANIES
              COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
                  PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
             EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
          CONDENSED COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
      (Dollars in millions, except per share data, unless otherwise noted)


     1. BASIS OF PRESENTATION (Exelon, ComEd, PECO and Generation)

               The accompanying consolidated financial statements as of June 30,
     2003 and for the three and six months then ended are unaudited,  but in the
     opinion of management of Exelon Corporation  (Exelon),  Commonwealth Edison
     Company (ComEd),  PECO Energy Company (PECO) and Exelon Generation Company,
     LLC (Generation)  include all adjustments that are considered necessary for
     a  fair  presentation  of  their  respective  financial   statements.   All
     adjustments  are  of  a  normal,  recurring  nature,  except  as  otherwise
     disclosed.  The December 31, 2002 Consolidated  Balance Sheets were derived
     from  audited  financial  statements  but do not  include  all  disclosures
     required by accounting  principles  generally accepted in the United States
     of America (GAAP).  Certain  prior-year  amounts have been reclassified for
     comparative purposes.  These  reclassifications had no effect on net income
     or  shareholders'  or  member's  equity.  These  notes  should  be  read in
     conjunction with the Notes to Consolidated  Financial Statements of Exelon,
     ComEd, PECO and Generation included in or incorporated by reference in ITEM
     8 of their Annual Report on Form 10-K for the year ended December 31, 2002.


     2. NEW ACCOUNTING PRINCIPLES AND ACCOUNTING CHANGES (Exelon, ComEd, PECO
        and Generation)

     Accounting Principles with a Cumulative Effect upon Adoption
     SFAS No. 143

               Statement  of  Financial  Accounting  Standards  (SFAS) No.  143,
     "Accounting  for Asset  Retirement  Obligations"  (SFAS No.  143)  provides
     accounting  requirements  for retirement  obligations  (whether  statutory,
     contractual or as a result of principles of promissory estoppel) associated
     with tangible  long-lived assets.  Exelon,  ComEd, PECO and Generation were
     required  to adopt  SFAS No.  143 as of  January  1,  2003.  A  significant
     retirement  obligation  is  Generation's  obligation  to  decommission  its
     nuclear plants at the end of their license lives  projected to be from 2029
     through 2056. These nuclear plants and the related nuclear  decommissioning
     trust fund  investments were transferred to Generation by ComEd and PECO in
     connection with the Exelon corporate restructuring on January 1, 2001.

               Generation  had  decommissioning  assets  of $3,316  million  and
     $3,053 million as of June 30, 2003 and December 31, 2002, respectively,  in
     trust accounts. Exelon and Generation anticipate that all trust fund assets
     will ultimately be used to decommission Generation's nuclear plants.


                                       21
<PAGE>


               After considering  interpretations  of the transitional  guidance
     included in SFAS No. 143,  Exelon  recorded  income of $112 million  (after
     income taxes) as a cumulative effect of a change in accounting principle in
     connection with its adoption of this standard in the first quarter of 2003.
     The  components  of  the  cumulative  effect  of  a  change  in  accounting
     principle, after income taxes, are as follows:

--------------------------------------------------------------------------------
  Generation (net of income taxes of $52)                            $     80
  Generation's investments in AmerGen Energy Company, LLC and
    Sithe Energies, Inc. (net of income taxes of $18)                      28
  ComEd (net of income taxes of $0)                                         5
  Exelon Enterprises Company, LLC (net of income taxes of $(1))            (1)
--------------------------------------------------------------------------------
      Total                                                          $    112
================================================================================

               The  cumulative  effect of the change in accounting  principle in
     adopting SFAS No. 143 had no impact on PECO's income statement.

               The asset  retirement  obligation (ARO) as of January 1, 2003 was
     determined  under SFAS No. 143 to be $2,366  million and $2,363 million for
     Exelon and  Generation,  respectively.  As  further  explained  below,  the
     adoption  also  resulted in recording  regulatory  assets and  liabilities.
     Accretion  expense for the three  months and six months ended June 30, 2003
     for Exelon was $39 million and $78 million, respectively. Accretion expense
     for the three months and six months ended June 30, 2003 for  Generation was
     $38 million and $77 million,  respectively.  The following table provides a
     reconciliation  of the AROs  reflected on the balance sheet at December 31,
     2002 and June 30, 2003:

                                                             Generation  Exelon
-------------------------------------------------------------------------------

 Accumulated depreciation                                     $2,845     $2,845
 Nuclear decommissioning liability for retired units           1,395      1,395
-------------------------------------------------------------------------------
   Decommissioning obligation at December 31, 2002             4,240      4,240
 Net reduction due to adoption of SFAS No. 143                 1,877      1,874
-------------------------------------------------------------------------------
   Decommissioning obligation at January 1, 2003               2,363      2,366
   Accretion expense for six months ended June 30, 2003           77         78
-------------------------------------------------------------------------------
 Asset retirement obligation at June 30, 2003                 $2,440     $2,444
================================================================================

              Determination of Asset Retirement Obligation

               In  accordance   with  SFAS  No.  143,  a   probability-weighted,
     discounted  cash flow model with  multiple  scenarios was used to determine
     the  "fair  value" of the  decommissioning  obligation.  SFAS No.  143 also
     stipulates  that fair  value  represents  the  amount a third  party  would
     receive for assuming an entity's entire obligation.

               The present value of future  estimated  cash flows was calculated
     using credit-adjusted  risk-free rates applicable to the various businesses
     in order to determine the fair value of Exelon's decommissioning obligation
     at the time of adoption of SFAS No. 143.


                                       22
<PAGE>


               Significant  changes  in the  assumptions  underlying  the  items
     discussed  above  could  materially  affect the balance  sheet  amounts and
     future  costs  related  to  decommissioning  recorded  in the  Consolidated
     Financial Statements.

               The following  tables set forth  Exelon's net income and earnings
     per common share for the three and six months ended June 30, 2002  adjusted
     as if SFAS No. 143 had been applied effective January 1, 2002.

<TABLE>
<CAPTION>

                                                                 Three Months Ended                   Six Months Ended
                                                                    June 30, 2002                      June 30, 2002
---------------------------------------------------------------------------------------------------------------------------
   Reported income before cumulative effect
<S>                                                                <C>                                      <C>
       of changes in accounting principles                         $      485                               $      722
   Adjustment as if SFAS No. 143 had been applied
        effective January 1, 2002                                          10                                       20
---------------------------------------------------------------------------------------------------------------------------
   Adjusted income before cumulative effect
       of changes in accounting principles                         $      495                               $       742
===========================================================================================================================


                                                                  Three Months Ended                   Six Months Ended
                                                                       June 30, 2002                      June 30, 2002
---------------------------------------------------------------------------------------------------------------------------
   Reported net income                                             $      485                               $      492
   Adjustment as if SFAS No. 143 had been applied
        effective January 1, 2002:
            Adjustment to income before cumulative effect
             of changes in accounting principles                           10                                        20
            Cumulative effect of changes in accounting principles          --                                       132
---------------------------------------------------------------------------------------------------------------------------
   Adjusted net income                                             $      495                               $       644
===========================================================================================================================


                                                                                       Three Months Ended June 30, 2002
                                                                                       --------------------------------
     Basic earnings per common share:                                        Reported        Adjustment (1)    Adjusted
---------------------------------------------------------------------------------------------------------------------------
     Income before cumulative effect
         of changes in accounting principles                               $     1.50        $    0.03        $   1.53
     Net income                                                            $     1.50        $    0.03        $   1.53
---------------------------------------------------------------------------------------------------------------------------

                                                                                       Three Months Ended June 30, 2002
                                                                                       --------------------------------
     Diluted earnings per common share:                                      Reported       Adjustment  (1)    Adjusted
---------------------------------------------------------------------------------------------------------------------------
     Income before cumulative effect
         of changes in accounting principles                               $     1.50        $    0.03        $   1.53
     Net income                                                            $     1.50        $    0.03        $   1.53
---------------------------------------------------------------------------------------------------------------------------
(1)      The adjustment represents the earnings impact as if SFAS No. 143 had been applied effective January 1, 2002.


                                                                                 Six Months Ended June 30, 2002
                                                                                 ------------------------------
     Basic earnings per common share:                                        Reported        Adjustment (1)    Adjusted
---------------------------------------------------------------------------------------------------------------------------
     Income before cumulative effect
         of changes in accounting principles                               $     2.24        $    0.06     $   2.30
     Net income                                                            $     1.53        $    0.47     $   2.00
---------------------------------------------------------------------------------------------------------------------------



                                       23
<PAGE>


                                                                                 Six Months Ended June 30, 2002
                                                                                 ------------------------------
     Diluted earnings per common share:                                      Reported       Adjustment  (1)    Adjusted
---------------------------------------------------------------------------------------------------------------------------
     Income before cumulative effect
         of changes in accounting principles                               $     2.23        $    0.06     $   2.29
     Net income                                                            $     1.52        $    0.47     $   1.99
---------------------------------------------------------------------------------------------------------------------------
(1)      The  adjustment  represents  the  earnings  impact as if SFAS No.  143 had been  applied  effective  January 1, 2002.

</TABLE>



              Effect of adopting SFAS No. 143

               Exelon was required to re-measure the decommissioning liabilities
     at fair  value  using  the  methodology  prescribed  by SFAS No.  143.  The
     transition  provisions  of SFAS No.  143  required  Exelon  to  apply  this
     re-measurement  back to the  historical  periods in which asset  retirement
     obligations  were  incurred,   resulting  in  a  re-measurement   of  these
     obligations at the date the related assets were acquired. Since the nuclear
     plants  previously  owned by ComEd were  acquired  by Exelon on October 20,
     2000 (Merger Date) as a result of the merger of Exelon,  Unicom Corporation
     and PECO  (Merger),  Exelon's  historical  accounting  for its ARO has been
     revised as if SFAS No. 143 had been in effect at the Merger Date.

               In the case of the former ComEd plants,  the  calculation  of the
     SFAS No. 143 ARO yielded  decommissioning  obligations lower than the value
     of the corresponding trust assets.  ComEd has previously  collected amounts
     from  customers  (which were  subsequently  transferred  to  Generation) in
     advance of Generation's  recognition of decommissioning  expense under SFAS
     No. 143. While it is expected that the trust assets will ultimately be used
     entirely for the  decommissioning  of the plants,  the current  measurement
     required  by SFAS No.  143  shows an  excess of  assets  over  related  ARO
     liabilities.  As such, in accordance with regulatory  accounting  practices
     and a December 2000 Illinois Commerce  Commission (ICC) Order, a regulatory
     liability of $948 million and a  corresponding  receivable  from Generation
     were recorded at ComEd upon the adoption of SFAS No. 143. At June 30, 2003,
     the  regulatory  liability and  corresponding  receivable  from  Generation
     totaled $1,094  million.  Exelon  believes that all of the  decommissioning
     assets,  including up to $73 million of annual  collections  through  2006,
     will be used to decommission the former ComEd plants.  Accordingly,  Exelon
     expects  the  regulatory   liability  and  corresponding   receivable  from
     Generation  will be  reduced  to zero at or before  the  conclusion  of the
     decommissioning of the former ComEd plants.

               In the case of the  former  PECO  plants,  the  SFAS No.  143 ARO
     calculation   yielded   decommissioning   obligations   greater   than  the
     corresponding  trust assets. As such, a regulatory asset of $20 million and
     a corresponding  payable to Generation were recorded upon adoption at PECO.
     At June 30,  2003,  the  regulatory  asset  and  corresponding  payable  to
     Generation   totaled  $16  million.   Exelon   believes  that  all  of  the
     decommissioning  assets,  including the $29 million of annual  collections,
     will be used to  decommission  the former PECO plants.  Exelon also expects
     the  regulatory  asset and  corresponding  payable  to  Generation  will be
     reduced to zero at the conclusion of the decommissioning of the former PECO
     plants.

               In accordance with regulatory accounting,  the net plant balances
     of Exelon,  ComEd and PECO include  recoveries for removal costs, which are
     included as a component of accumulated  depreciation.  The adoption of SFAS
     No. 143 had no impact on the  accounting  for removal costs not  associated
     with AROs.


                                       24
<PAGE>


               Prior to the adoption of SFAS No. 143,  Generation's  accumulated
     depreciation  included  $2,845  million  for  decommissioning   liabilities
     related to the active plants.  This amount was  reclassified to an ARO upon
     the adoption of SFAS No. 143.  Additionally,  Generation adjusted the total
     decommissioning  liability  for the ComEd plants to $1,575  million and for
     the PECO plants to $787 million. As described above,  Generation recorded a
     payable to ComEd of $948 million and a receivable from PECO of $20 million.
     Generation  also  recorded  an asset  retirement  cost asset  (ARC) of $172
     million  related to the  establishment  of the PECO ARO in accordance  with
     SFAS No. 143. The ARC will be  amortized  over the  remaining  lives of the
     plants.

               As discussed above,  Exelon re-measured its 2001  decommissioning
     related  balances  associated with the Merger purchase price  allocation at
     ComEd and the January 2001 corporate  restructuring  as if SFAS No. 143 had
     been in effect at the Merger Date. Exelon and ComEd concluded that had SFAS
     No. 143 been in effect,  ComEd would not have recorded an impairment on its
     regulatory  asset for  decommissioning  of its retired  nuclear plants as a
     purchase  price  allocation  adjustment in 2001 as a result of the December
     2000 ICC  order.  Increased  net  assets  would  have been  transferred  to
     Generation by ComEd in the  corporate  restructuring.  Accordingly,  Exelon
     recorded a reduction  of goodwill of  approximately  $210  million,  with a
     corresponding  reduction  in  its  overall  decommissioning  obligation  in
     connection  with the  implementation  of SFAS No.  143 on  January 1, 2003.
     Similarly,  ComEd  recorded a reduction  of $210 million of goodwill and of
     shareholders'  equity,  and Generation  recorded a $210 million increase in
     member's  equity  and a  corresponding  reduction  of  its  decommissioning
     obligation. In addition, Exelon and ComEd recorded a cumulative effect of a
     change  in  accounting   principle  of  $5  million  to  reverse   goodwill
     amortization  that had  been  recorded  in  2001.  Exelon  and  ComEd  also
     reclassified a regulatory  asset related to nuclear  decommissioning  costs
     for retired units of $248 million to regulatory liabilities.

               In accordance  with the provisions of SFAS No. 143 and regulatory
     accounting  guidance,  Exelon  and  Generation  recorded  a  SFAS  No.  143
     transition   adjustment  to  accumulated  other  comprehensive   income  to
     reclassify $168 million of accumulated net unrealized losses on the nuclear
     decommissioning trust funds to regulatory assets and liabilities.

               The following  tables set forth ComEd and Generation's net income
     and Generation's  income before  cumulative effect of changes in accounting
     principles  for the three and six months ended June 30, 2002 adjusted as if
     SFAS No. 143 had been applied  effective  January 1, 2002.  ComEd's  income
     before  cumulative  effect  of a change  in  accounting  principle  was not
     affected by the adoption of SFAS No. 143.

<TABLE>
<CAPTION>


                                                                  Three Months Ended       Six Months Ended
     ComEd                                                             June 30, 2002          June 30, 2002
-------------------------------------------------------------------------------------------------------------
<S>                                                                    <C>                      <C>
   Reported net income                                                 $  231                   $  360
   Adjustment as if SFAS No. 143 had been applied
        effective January 1, 2002:
            Cumulative effect of changes in accounting principles          --                        5
-------------------------------------------------------------------------------------------------------------
   Adjusted net income                                                 $  231                   $  365
=============================================================================================================


                                       25
<PAGE>


                                                                  Three Months Ended        Six Months Ended
     Generation                                                        June 30, 2002           June 30, 2002
------------------------------------------------------------------------------------------------------------
     Reported income before cumulative effect
         of changes in accounting principles                           $   84                   $  150
     Adjustment as if SFAS No. 143 had been applied
          effective January 1, 2002                                        10                       20
------------------------------------------------------------------------------------------------------------
     Adjusted income before cumulative effect
         of changes in accounting principles                           $   94                   $  170
=============================================================================================================


                                                                  Three Months Ended          Six Months Ended
     Generation                                                        June 30, 2002             June 30, 2002
------------------------------------------------------------------------------------------------------------
     Reported net income                                               $   84                  $   163
     Adjustment as if SFAS No. 143 had been applied
          effective January 1, 2002:
              Adjustment to income before cumulative effect
               of changes in accounting principles                         10                       20
              Cumulative effect of changes in accounting principles        --                      128
------------------------------------------------------------------------------------------------------------
     Adjusted net income                                               $   94                  $   311
=============================================================================================================
</TABLE>

              Accounting methodology under SFAS No. 143

               For the  former  ComEd  plants,  realized  gains  and  losses  on
     decommissioning trust funds are reflected in other income and deductions in
     Generation's  Consolidated  Statements of Income and Comprehensive  Income,
     while the unrealized gains and losses on marketable  securities held in the
     trust  funds  adjust the payable  Generation  currently  has to ComEd.  The
     increases in the ARO are recorded in operating and  maintenance  expense as
     accretion expense,  while the funds received from ComEd for decommissioning
     are  recorded in revenue.  Generation's  payable to ComEd is adjusted  each
     reporting  period to reflect the  difference  between  the  decommissioning
     assets and the ARO levels.  As such,  if the ARO increases at a rate faster
     than the increase in the trust fund assets,  ComEd's  regulatory  liability
     and receivable from Generation will decrease.  If and when the trust assets
     are exceeded by the  decommissioning  liability,  Generation is responsible
     for any shortfall in funding.  The result of the above accounting will have
     no earnings impact to Generation for as long as the trust assets exceed the
     decommissioning liabilities for the former ComEd plants.

               The above  accounting  practices are also  applicable  for former
     PECO plants owned by Generation. Additionally, depreciation expense will be
     recognized on the ARC established  upon adoption of SFAS No. 143.  However,
     as PECO has the expectation of full recovery of decommissioning  costs, the
     result of the above  accounting will ultimately  reflect no earnings impact
     to  Generation.  Therefore,  to the extent that the net of  decommissioning
     revenues collected and realized investment income differ from the accretion
     expense to the  decommissioning  liability and the related  depreciation of
     the ARC,  an  adjustment  to net the  amounts to zero would be  recorded by
     Generation  for that  period  with the  offset to PECO's  regulatory  asset
     balance.

               The ongoing  effects to  Generation  for the  accounting  for the
     decommissioning  of the AmerGen Energy  Company,  LLC (AmerGen)  plants are
     recorded within Generation's equity in earnings of AmerGen.


                                       26
<PAGE>


               SFAS No. 141 and SFAS No. 142

               In 2001,  the FASB issued SFAS No. 141,  "Business  Combinations"
     (SFAS No. 141), which requires that all business  combinations be accounted
     for under the purchase  method of accounting and  establishes  criteria for
     the  separate   recognition  of  intangible  assets  acquired  in  business
     combinations.  In addition, SFAS No. 141 required that unamortized negative
     goodwill related to pre-July 1, 2001 purchases be recognized as a change in
     accounting  principle  concurrent  with  the  adoption  of  SFAS  No.  142,
     "Goodwill  and Other  Intangible  Assets"  (SFAS No. 142).  Upon  AmerGen's
     adoption  of SFAS  No.  141 in  January  2002,  Generation  recognized  its
     proportionate  share of income of $22 million ($13  million,  net of income
     taxes) as a cumulative effect of a change in accounting principle.

               Exelon,  ComEd,  PECO and  Generation  adopted SFAS No. 142 as of
     January 1, 2002.  SFAS No. 142  established  new  accounting  and reporting
     standards for goodwill and intangible  assets.  Exelon recorded a charge of
     $357 million ($243 million, net of income taxes and minority interest) upon
     the adoption of SFAS No. 142 with  respect to goodwill  recorded in certain
     reporting units of Exelon  Enterprises  Company,  LLC  (Enterprises).  This
     charge  was  recorded  as a  cumulative  effect of a change  in  accounting
     principle in the first quarter of 2002.

              The components of the net transitional impairment loss recognized
     in the first quarter of 2002 as a cumulative effect of a change in
     accounting principle are as follows:
<TABLE>
<CAPTION>

-----------------------------------------------------------------------------------------------------
<S>                                                          <C>                     <C>
     Enterprises goodwill impairment (net of income taxes of $(103))                 $    (254)
     Minority interest (net of income taxes of $4)                                          11
     Elimination of AmerGen negative goodwill (net of income taxes of $9)                   13
-----------------------------------------------------------------------------------------------------
     Total cumulative effect of a change in accounting principle                     $    (230)
=====================================================================================================
</TABLE>


               At June 30, 2003,  Exelon had goodwill of $4,735 million of which
     $4,711  million  relates  to ComEd and the  remaining  goodwill  relates to
     Enterprises'  reporting units. See Note 3 - Acquisitions,  Dispositions and
     Retirements for a further discussion of Enterprises'  goodwill.  Consistent
     with SFAS No. 142, the remaining  goodwill is reviewed for impairment on an
     annual basis,  or more  frequently if  significant  events occur that could
     indicate an impairment exists.  ComEd and Enterprises  perform their annual
     reviews in the fourth  quarter of their  fiscal  years.  The annual  update
     impairment  review  during the fourth  quarter of 2002 did not identify any
     goodwill impairment.

     Other Accounting Principles and Accounting Changes
     SFAS No. 146

               In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs
     Associated with Exit or Disposal  Activities"  (SFAS No. 146). SFAS No. 146
     requires  that the  liability  for costs  associated  with exit or disposal
     activities  be  recognized  when  incurred,  rather  than at the  date of a
     commitment  to an exit or  disposal  plan.  SFAS No.  146 is to be  applied
     prospectively to exit or disposal  activities  initiated after December 31,
     2002.  Exelon,  ComEd,  PECO and  Generation's  results of operations  were
     unaffected by the adoption SFAS No. 146.


                                       27
<PAGE>


     FIN No. 45

               In November 2002, the FASB released FASB Interpretation (FIN) No.
     45,  "Guarantor's  Accounting and Disclosure  Requirements  for Guarantees,
     Including  Indirect  Guarantees  of  Indebtedness  of Others" (FIN No. 45),
     providing for expanded  disclosures  and recognition of a liability for the
     fair value of the obligation undertaken by the guarantor. Under FIN No. 45,
     guarantors  are  required  to  disclose  the nature of the  guarantee,  the
     maximum amount of potential  future  payments,  the carrying  amount of the
     liability  and the nature and amount of recourse  provisions  or  available
     collateral that would be recoverable by the guarantor.  Exelon, ComEd, PECO
     and Generation adopted the disclosure  requirements under FIN No. 45, which
     were  effective for financial  statements  for periods ended after December
     15, 2002. The  recognition  and  measurement  provisions of FIN No. 45 were
     effective for  guarantees  issued or modified  after December 31, 2002. The
     adoption of FIN No. 45 had no  material  effect on Exelon,  ComEd,  PECO or
     Generation's results of operations.  Liabilities associated with guarantees
     entered  into during the six months  ended June 30, 2003 are  reflected  in
     Note 8 - Commitments and Contingencies.

     SFAS No. 148

               In December 2002, the FASB issued SFAS No. 148,  "Accounting  for
     Stock-Based Compensation - Transition and Disclosure - an amendment of FASB
     Statement  No.  123"  (SFAS No.  148).  SFAS No. 148  provides  alternative
     methods of transition for a voluntary change to the fair value based method
     of  accounting  for   stock-based   employee   compensation   and  requires
     disclosures in both annual and interim financial  statements  regarding the
     method of accounting  for  stock-based  compensation  and the effect of the
     method on  financial  results.  SFAS No. 148 was  effective  for  financial
     statements for fiscal years ended after  December 15, 2002.  Exelon adopted
     the  additional  disclosure  requirements  of SFAS No. 148 and continues to
     account  for  its  stock-compensation   plans  under  the  disclosure  only
     provision of SFAS No. 123, "Accounting for Stock-Based  Compensation" (SFAS
     No.  123).  The tables below show the effect on net income and earnings per
     share  for  Exelon  and the  effect  on net  income  for  ComEd,  PECO  and
     Generation had Exelon elected to account for stock-based compensation plans
     using the fair value method under SFAS No. 123 for the three and six months
     ended June 30, 2003 and 2002:


                                       28
<PAGE>

<TABLE>
<CAPTION>

     Exelon
                                                                                   Three Months Ended June 30,
                                                                                   ---------------------------
                                                                                             2003       2002
------------------------------------------------------------------------------------------------------------
<S>                                                                                     <C>           <C>
     Net income - as reported                                                           $     372     $  485
     Deduct: Total stock-based compensation expense
        determined under fair value based method for all
        awards, net of income taxes                                                            (5)        (8)
------------------------------------------------------------------------------------------------------------
     Pro forma net income                                                               $     367     $  477
============================================================================================================
     Earnings per share:
        Basic - as reported                                                             $    1.14     $  1.50
        Basic - pro forma                                                               $    1.13     $  1.48

        Diluted - as reported                                                           $    1.14     $  1.50
        Diluted - pro forma                                                             $    1.12     $  1.47
------------------------------------------------------------------------------------------------------------

                                                                                   Six Months Ended June 30,
                                                                                   -------------------------
                                                                                             2003       2002
------------------------------------------------------------------------------------------------------------
     Net income - as reported                                                           $     733     $  492
     Deduct: Total stock-based compensation expense
        determined under fair value based method for all
        awards, net of income taxes                                                           (10)       (17)
------------------------------------------------------------------------------------------------------------
     Pro forma net income                                                               $     723     $  475
============================================================================================================
     Earnings per share:
        Basic - as reported                                                             $    2.26     $  1.53
        Basic - pro forma                                                               $    2.23     $  1.48

        Diluted - as reported                                                           $    2.24     $  1.52
        Diluted - pro forma                                                             $    2.21     $  1.47
------------------------------------------------------------------------------------------------------------

     ComEd
                                                                                   Three Months Ended June 30,
                                                                                   -------------------------
                                                                                             2003       2002
------------------------------------------------------------------------------------------------------------
     Net income - as reported                                                           $     205     $  231
     Deduct: Total stock-based compensation expense
        determined under fair value based method for all
        awards, net of income taxes                                                            (1)        (3)
------------------------------------------------------------------------------------------------------------
     Pro forma net income                                                               $     204     $  228
============================================================================================================

                                                                                   Six Months Ended June 30,
                                                                                   -------------------------
                                                                                             2003       2002
------------------------------------------------------------------------------------------------------------
     Net income - as reported                                                           $     401     $  360
     Deduct: Total stock-based compensation expense
        determined under fair value based method for all
        awards, net of income taxes                                                            (2)        (6)
------------------------------------------------------------------------------------------------------------
     Pro forma net income                                                               $     399     $  354
============================================================================================================


</TABLE>

                                       29
<PAGE>

<TABLE>
<CAPTION>

     PECO
                                                                                  Three Months Ended June 30,
                                                                                   -------------------------
                                                                                             2003       2002
------------------------------------------------------------------------------------------------------------
<S>                                                                                     <C>           <C>
     Net income on common stock- as reported                                            $      86     $  91
     Deduct: Total stock-based compensation expense
        determined under fair value based method for all
        awards, net of income taxes                                                            (1)       (3)
------------------------------------------------------------------------------------------------------------
     Pro forma net income on common stock                                               $      85     $  88
============================================================================================================

                                                                                   Six Months Ended June 30,
                                                                                   -------------------------
                                                                                             2003       2002
------------------------------------------------------------------------------------------------------------
     Net income on common stock- as reported                                            $     221     $  177
     Deduct: Total stock-based compensation expense
        determined under fair value based method for all
        awards, net of income taxes                                                            (1)        (7)
------------------------------------------------------------------------------------------------------------
     Pro forma net income on common stock                                               $     220     $  170
============================================================================================================

     Generation
                                                                                  Three Months Ended June 30,
                                                                                   -------------------------
                                                                                             2003       2002
------------------------------------------------------------------------------------------------------------
     Net income - as reported                                                           $     142      $  84
     Deduct: Total stock-based compensation expense
        determined under fair value based method for all
        awards, net of income taxes                                                            (3)        (4)
------------------------------------------------------------------------------------------------------------
     Pro forma net income                                                               $     139      $  80
============================================================================================================

                                                                                   Six Months Ended June 30,
                                                                                   -------------------------
                                                                                             2003       2002
------------------------------------------------------------------------------------------------------------
     Net income - as reported                                                           $     197     $  163
     Deduct: Total stock-based compensation expense
        determined under fair value based method for all
        awards, net of income taxes                                                            (5)        (7)
------------------------------------------------------------------------------------------------------------
     Pro forma net income                                                               $     192     $  156
============================================================================================================

</TABLE>


     FIN No. 46

               In January 2003,  the FASB issued FIN No. 46,  "Consolidation  of
     Variable   Interest   Entities"   (FIN  No.  46).   FIN  No.  46  addresses
     consolidating certain variable interest entities and applies immediately to
     variable  interest  entities  created  after  January 31, 2003.  FIN No. 46
     requires Exelon to consolidate  pre-existing  variable interest entities as
     of July 1, 2003.

               Based on management's interpretation of the provisions of FIN No.
     46, it is  reasonably  possible  that  Generation  will  consolidate  Sithe
     Energies,  Inc. (Sithe) as of July 1, 2003.  Generation is a 49.9% owner of
     Sithe  and has  accounted  for  this  entity  as an  unconsolidated  equity
     investment  through June 30, 2003. Sithe owns and operates power generating
     facilities.  Refer  to  Note  17 -  Unconsolidated  Equity  Investments  in
     Generation's  Form 10-K for the year ended  December 31, 2002 and Note 10 -
     Unconsolidated  Investments for further information related to Generation's
     investment  in  Sithe.  FIN No.  46 is a complex  accounting  standard  and
     requires  management to exercise judgment in analyzing  entities with which
     Exelon and its


                                       30
<PAGE>


     subsidiaries have business  arrangements to determine if those entities are
     variable interest  entities and, if so, whether  consolidation is required.
     This  accounting  standard is the subject of continuing  discussions by the
     FASB and others. The final determination of entities that may be considered
     variable interest entities will be completed in the third quarter of 2003.

     SFAS No. 149

               In April  2003,  the FASB  issued  SFAS No.  149,  "Amendment  of
     Statement 133 on Derivative  Instruments and Hedging  Activities" (SFAS No.
     149). SFAS No. 149 amends and clarifies financial  accounting and reporting
     for  derivative  instruments,   including  certain  derivative  instruments
     embedded in other contacts,  and for hedging activities under SFAS No. 133,
     "Accounting for Derivative  Instruments and Hedging  Activities"  (SFAS No.
     133).  SFAS No. 149 also amends SFAS No. 133 for decisions made (1) as part
     of the Derivatives  Implementation  Group process that effectively required
     amendments  to SFAS No. 133,  (2) in  connection  with other FASB  projects
     dealing  with   financial   instruments,   and  (3)  in   connection   with
     implementation  issues  raised  in  relation  to  the  application  of  the
     definition of a derivative.

               SFAS No. 149 is effective for contracts  entered into or modified
     after June 30, 2003, except as stated below, and for hedging  relationships
     designated  after June 30, 2003. In addition,  except as stated below,  all
     provisions of SFAS No. 149 will be applied prospectively.

               The  provisions  of SFAS No.  149  that  relate  to SFAS No.  133
     implementation  issues that have been  effective  for fiscal  quarters that
     began prior to June 15, 2003  should  continue to be applied in  accordance
     with their  respective  effective  dates. In addition,  certain  provisions
     relating to forward  purchases or sales of when-issued  securities or other
     securities  that  do not yet  exist  should  be  applied  to both  existing
     contracts and new contracts  entered into after June 30, 2003. The adoption
     of SFAS No. 149 will have no impact on the  Consolidated  Balance Sheets or
     Statements of Income and  Comprehensive  Income of Exelon,  ComEd, PECO and
     Generation.

     SFAS No. 150

               In May  2003,  the FASB  issued  SFAS No.  150,  "Accounting  for
     Certain Financial  Instruments with Characteristics of both Liabilities and
     Equity" (SFAS No. 150). SFAS No. 150 requires that certain instruments that
     have  characteristics  of both  liabilities  and  equity be  classified  as
     liabilities  in the statement of financial  position.  SFAS No. 150 affects
     the  accounting  for three  types of  freestanding  financial  instruments:
     mandatorily  redeemable  shares,  instruments  that do or may  require  the
     issuer to buy back some of its shares in exchange for cash or other assets,
     and  obligations  that can be settled  with shares,  the monetary  value of
     which is fixed, tied solely or predominantly to a variable such as a market
     index, or varies inversely with the value of the issuer's shares.

               Most  of the  guidance  in  SFAS  No.  150 is  effective  for all
     financial  instruments  entered into or modified  after May 31,  2003,  and
     otherwise is effective for Exelon as of July 1, 2003.

               During June 2003,  PECO issued  $100  million of trust  preferred
     securities.  These  securities  were recorded as liabilities  (see Note 9 -
     Long-Term Debt and Preferred  Securities).


                                       31
<PAGE>


     Effective July 1, 2003, Exelon, ComEd and PECO will reclassify  mandatorily
     redeemable  shares that were issued prior to May 31, 2003 as liabilities on
     their respective  balance sheets. The total amounts to be reclassified will
     be $422 million, $344 million and $78 million,  respectively.  The adoption
     of SFAS No. 150 will have no impact on Generation.

               Change in Accounting Estimate ComEd Effective July 1, 2002, ComEd
     lowered its depreciation rates based on a depreciation study reflecting its
     significant   construction   program  in  recent  years,   changes  in  and
     development  of new  technologies,  and changes in estimated  plant service
     lives  since the last  depreciation  study.  The  annualized  reduction  in
     depreciation  expense,  based on  December  31,  2001 plant  balances,  was
     estimated  to be  approximately  $100 million  ($60  million,  after income
     taxes).  As a result of the change,  operating income for the three and six
     months  ended June 30,  2003  increased  approximately  $24 million and $48
     million,  respectively  ($14 million and $29 million,  respectively,  after
     income taxes) compared to the three and six months ended June 30, 2002.


     3. ACQUISITIONS, DISPOSITIONS AND RETIREMENTS (Exelon and Generation)

     InfraSource Sale

               On June 18, 2003,  Enterprises  entered into an agreement to sell
     the electric construction and services,  underground and telecom businesses
     of InfraSource, Incorporated (InfraSource). The net cash proceeds to Exelon
     from  the  sale  are  expected  to be  $211  million  plus  a  $30  million
     subordinated  note maturing with interest in 2011. The interest rate on the
     note is 8% annually if paid in cash and 10% if paid in kind.  In connection
     with this transaction,  Enterprises will enter into an agreement at closing
     that may  result  in  certain  payments  to  InfraSource  if the  amount of
     services Exelon purchases from  InfraSource  during the period from closing
     through  2006  is  below  specified  thresholds.   Enterprises  anticipates
     incurring  approximately  $5 million in closing costs  associated  with the
     transaction. Closing of the transaction is subject to the satisfaction of a
     number of  conditions,  including  regulatory  approvals from state utility
     commissions in Pennsylvania,  Delaware, New Jersey, Virginia,  Maryland and
     Washington,  D.C. and other conditions, the satisfaction of which cannot be
     assured.  Early  termination  of the Hart Scott Rodino  waiting  period was
     granted  effective July 17, 2003. If all closing  conditions are satisfied,
     the  transaction  is  expected  to close in the third or fourth  quarter of
     2003.

               Exelon  classified the assets and liabilities of InfraSource that
     are  subject  to the  agreement  of  sale  as  held  for  sale  within  the
     Consolidated  Balance Sheet pursuant to SFAS No. 144,  "Accounting  for the
     Impairment or Disposal of Long-Lived  Assets" (SFAS No. 144) as of June 30,
     2003. These businesses are reported under the Enterprises  segment pursuant
     to SFAS No. 131,  "Disclosures  about Segments of an Enterprise and Related
     Information."  The major  classes of assets and  liabilities  classified as
     held for sale as of June 30, 2003 consist of the following (in millions):


                                       32
<PAGE>


------------------------------------------------------------------------------
     Cash                                                       $           26
     Accounts receivable, net                                               82
     Inventory                                                              13
     Property, plant and equipment, net                                    122
     Deferred income taxes                                                  62
     Other assets                                                           47
------------------------------------------------------------------------------
     Total assets classified as held for sale                   $          352
==============================================================================


------------------------------------------------------------------------------
     Accounts payable                                           $           13
     Accrued expenses and other current liabilities                         53
     Other liabilities                                                      15
------------------------------------------------------------------------------
     Total liabilities classified as held for sale              $           81
==============================================================================

               In connection with the sale, Exelon recorded an impairment charge
     of approximately $47 million (before income taxes) pursuant to SFAS No. 142
     related to the goodwill  recorded  within the  InfraSource  reporting unit.
     Management of Exelon and  Enterprises  primarily  considered the negotiated
     sales  price of  InfraSource  in  determining  the  amount of the  goodwill
     impairment charge.  This impairment charge was recorded as an operating and
     maintenance  expense  within  the  Consolidated  Statements  of Income  and
     Comprehensive Income.

     Sale of Investment in AT&T Wireless

               On April 1,  2002,  Enterprises  sold  its 49%  interest  in AT&T
     Wireless PCS of Philadelphia, LLC to a subsidiary of AT&T Wireless Services
     for $285  million  in cash.  Enterprises  recorded  a gain of $116  million
     (after  income  taxes) on the $84 million  investment  in other  income and
     deductions on Exelon's Consolidated  Statements of Income and Comprehensive
     Income.

     Generation
     Sithe New England Holdings Acquisition

               On November 1, 2002, Generation purchased the assets of Sithe New
     England  Holdings,  LLC (now known as Exelon New England),  a subsidiary of
     Sithe, and related power marketing  operations.  The purchase price for the
     Exelon New England  assets  consisted of a $536 million note to Sithe,  $14
     million  of direct  acquisition  costs  and a $208  million  adjustment  to
     Generation's  previously existing investment in Sithe related to Exelon New
     England.  In connection with the  acquisition,  Generation  assumed certain
     Sithe  guarantees,  including a guarantee of an equity  contribution  to be
     made to Sithe Boston  Generating,  LLC  (currently  known as Exelon  Boston
     Generating,  LLC  (EBG)),  a  project  subsidiary  of Exelon  New  England.
     Pursuant to Generation's  assumed equity guarantee,  upon the occurrence of
     certain events,  Generation  would be obligated to (1) contribute up to $38
     million of equity for the purpose of  completing  the  construction  of two
     generating  facilities  (2) pay certain  taxes,  and/or (3)  contribute  to
     certain reserve funds.


                                       33
<PAGE>


          EBG has a $1.25  billion  credit  facility (EBG  Facility),  which was
     entered into  primarily to finance the  construction  of the Mystic 8 and 9
     and Fore River  generating  units. The  approximately  $1.1 billion of debt
     outstanding  under the credit  facility  at June 30, 2003 is  reflected  in
     Exelon and Generation's  Consolidated Balance Sheets as a current liability
     due to certain events of default  described  below.  Generation made a cash
     payment to Sithe of approximately $210 million during the second quarter of
     2003 related to the note payable associated with the acquisition.  See Note
     9 - Long-Term  Debt and Preferred  Securities  for  additional  information
     regarding this note.

              The allocation of the purchase price to the fair value of assets
     acquired and liabilities assumed in the acquisition was as follows:

--------------------------------------------------------------------------------
     Current assets (including $12 million of cash acquired)        $       85
     Property, plant and equipment                                       1,949
     Deferred debits and other assets                                       63
     Current liabilities                                                  (154)
     Deferred credits and other liabilities                               (149)
     Long-term debt                                                     (1,036)
--------------------------------------------------------------------------------
     Total purchase price                                           $      758
================================================================================

         The EBG Facility  requires  that all of the projects  achieve  "Project
     Completion," as defined in the EBG Facility (Project  Completion),  by June
     12, 2003.  On June 11,  2003,  EBG  negotiated  an extension of the Project
     Completion  date to July 11, 2003.  On July 3, 2003,  the lenders under the
     EBG Facility  and EBG executed a letter  agreement as a result of which the
     lenders are  precluded  during the period July 11, 2003 through  August 29,
     2003 from exercising any remedies  resulting from the failure of all of the
     projects to achieve  Project  Completion.  At that time, EBG stated that it
     would continue to monitor the projects,  assess all of its options relating
     to the projects, and continue discussions with the lenders.  Mystic 8 and 9
     are in commercial  operation,  although  construction has not progressed to
     the  point  of   Project   Completion.   Construction   of  Fore  River  is
     substantially  complete and the unit is currently  undergoing testing.  EBG
     does not anticipate  that the projects will achieve  Project  Completion by
     August 29, 2003. The EBG Facility is  non-recourse to Exelon and Generation
     and an event of default under the EBG Facility does not constitute an event
     of default under any other debt instruments of Exelon or its subsidiaries.

               As a result of Exelon's continuing evaluation of the projects and
     discussions with the lenders in July 2003, Exelon has commenced the process
     of an orderly transition out of the ownership of EBG and the projects.  The
     transition  will  take  place in a manner  that  complies  with  applicable
     regulatory  requirements.  For a period of time, Exelon expects to continue
     to provide  administrative and operational services to EBG in its operation
     of the projects.  Exelon informed the lenders of Exelon's  decision to exit
     and that it will not provide  additional funding to the projects beyond its
     existing contractual  obligations.  Exelon cannot predict the timing of the
     transition.

               Exelon  expects  Generation  will incur an  impairment of its EBG
     related assets, which, in aggregate, could reach approximately $550 million
     after income taxes.


                                       34
<PAGE>


     Retirement of Power Plants

               Generation  filed a request  with the New  England  ISO to retire
     Exelon  New  England's  Mystic 4, 5 and 6 and New Boston  units  based upon
     management's  view of the ongoing  financial  viability of the units due to
     the start up of Mystic Units 8 and 9. Pursuant to SFAS No. 144,  Generation
     performed a fair value analysis  associated with the pending  retirement of
     Mystic  Units 4, 5, and 6 and New Boston.  Based on a  probability-weighted
     undiscounted  cash flow model,  Generation  determined  that the book value
     exceeded  the  fair  value  by $5  million  for  Mystic  Units  4, 5 and 6.
     Therefore, an impairment charge of $5 million was recorded as operating and
     maintenance expense in Exelon and Generation's  Consolidated  Statements of
     Income and Comprehensive Income for the three months ended June 30, 2003.

     Acquisition of Generating Plants from TXU

               On April  25,  2002,  Generation  acquired  two  natural-gas  and
     oil-fired  plants from TXU Corp.  (TXU) for an aggregate  purchase price of
     $443  million.  The  purchase  included  the 893-MW  Mountain  Creek  Steam
     Electric  Station in Dallas,  Texas and the 1,441-MW Handley Steam Electric
     Station in Fort Worth,  Texas.  The transaction  included a purchased power
     agreement  for TXU to  purchase  power  during  the  months of May  through
     September  from 2002  through  2006.  During  the  periods  covered  by the
     purchased  power  agreement,  TXU has agreed to fixed capacity and variable
     expense  payments,  and to provide  fuel to Exelon in return for  exclusive
     rights to the energy and capacity of the generation  plants.  Substantially
     all of the purchase price was allocated to property, plant and equipment.


4. REGULATORY ISSUES (Exelon, ComEd and PECO)

     ComEd

               On March 3, 2003,  ComEd  entered into an agreement  with various
     Illinois  electric  retail  market  suppliers,   key  customer  groups  and
     governmental  parties regarding several matters affecting ComEd's rates for
     electric service (Agreement).  The Agreement addressed, among other things,
     issues related to ComEd's delivery  services rate proceeding,  market value
     index  proceeding,  the process for competitive  service  declarations  for
     large-load  customers and an amendment and extension of the purchased power
     agreement (PPA) with Generation. During the second quarter of 2003, the ICC
     issued orders consistent with the Agreement which is now effective.

               During  the first  quarter  of 2003,  ComEd  recorded a charge to
     earnings, associated with the funding of specified programs and initiatives
     associated  with the Agreement,  of $51 million  (before income taxes) on a
     present value basis.  This amount was partially offset by the reversal of a
     $12 million (before income taxes) reserve  established in the third quarter
     of 2002 for a potential  capital  disallowance in ComEd's delivery services
     rate proceeding,  and a credit of $10 million (before income taxes) related
     to the  capitalization of employee  incentive  payments provided for in the
     delivery  services  order.  The charge of $51 million and the credit of $10
     million were recorded in operating and maintenance expense and the reversal
     of the $12  million  reserve  was  recorded  in other,  net within  ComEd's
     Consolidated  Statements  of  Income  and  Comprehensive  Income.  The  net
     one-time charge for these items


                                       35
<PAGE>


     was $29 million  (before income taxes).  In accordance  with the Agreement,
     ComEd made payments of $17 million during the second quarter of 2003.

     PECO

               As previously  reported in the 2002 Form 10-K,  the  Pennsylvania
     Utility  Commission's (PUC) Final Electric  Restructuring Order established
     market share thresholds (MST) to promote  competition.  On May 1, 2003, the
     PUC approved the residential  customer plan filed by PECO in February 2003.
     Under the plan, a total of 375,000 residential customers may be transferred
     to alternative  electric generation  suppliers in December 2003.  Customers
     transferred  will have the  right to return to PECO at any time.  PECO does
     not expect the  transfer  of  customers  pursuant to the MST plan to have a
     material  impact on its results of operations,  financial  position or cash
     flows.

     5.  EARNINGS PER SHARE (Exelon)

               Diluted  earnings per share are calculated by dividing net income
     by the  weighted  average  number of shares  of common  stock  outstanding,
     including shares issuable upon exercise of stock options  outstanding under
     Exelon's stock option plans considered to be common stock equivalents.  The
     following  table  shows the effect of these stock  options on the  weighted
     average number of shares  outstanding used in calculating  diluted earnings
     per share (in millions):

<TABLE>
<CAPTION>

                                                          Three Months Ended June 30,         Six Months Ended June 30,
                                                          --------------------------          --------------------------
                                                              2003              2002             2003              2002
------------------------------------------------------------------------------------------------------------------------
<S>                                                            <C>               <C>              <C>               <C>
     Average Common Shares Outstanding                         325               322              324               322
     Assumed Exercise of Stock Options                           2                 2                3                 2
------------------------------------------------------------------------------------------------------------------------
     Average Dilutive Common Shares Outstanding                327               324              327               324
========================================================================================================================

</TABLE>


               The number of stock options not included in average common shares
     used in calculating  diluted  earnings per share due to their  antidilutive
     effect were five  million for the three and six months  ended June 30, 2003
     and three million for the three and six months ended June 30, 2002.


                                       36
<PAGE>



     6. SEGMENT INFORMATION (Exelon, ComEd, PECO and Generation)

               Exelon  operates  in three  business  segments:  Energy  Delivery
     (ComEd  and  PECO),  Generation  and  Enterprises.   Exelon  evaluates  the
     performance of its business segments on the basis of net income.

               ComEd,  PECO and  Generation  each  operate in a single  business
     segment;  as such, no separate  segment  information  is provided for these
     registrants.

               Exelon's  segment  information for the three and six months ended
     June 30,  2003 and 2002 and at June 30,  2003 and  December  31, 2002 is as
     follows:

     Three Months Ended June 30, 2003 and 2002

<TABLE>
<CAPTION>

                                                                                       Corporate and
                                          Energy                                        Intersegment
                                        Delivery     Generation      Enterprises        Eliminations       Consolidated
------------------------------------------------------------------------------------------------------------------------
     Total Revenues (1):
<S>  <C>                              <C>            <C>             <C>              <C>                  <C>
     2003                             $    2,322     $    1,886      $        443     $         (930)      $      3,721
     2002                                  2,476          1,559               476               (992)             3,519
     Intersegment Revenues:
     2003                             $       19     $      896      $         16     $         (931)      $         --
     2002                                     15            953                24               (992)                --
     Income (Loss) Before Income Taxes:
     2003                             $      481     $      233      $        (95)    $          (25)      $        594
     2002                                    522            135               142                (35)               764
     Income Taxes:
     2003                             $      190     $       91      $        (34)    $          (25)      $        222
     2002                                    200             51                59                (31)               279
     Net Income (Loss):
     2003                             $      291     $      142      $        (61)    $           --       $        372
     2002                                    322             84                83                 (4)               485
------------------------------------------------------------------------------------------------------------------------
</TABLE>

(1)      $51 million and $57 million in utility taxes are included in the
         Revenues and Expenses for the three months ended June 30, 2003 and
         2002, respectively, for ComEd. $47 million and $49 million in utility
         taxes are included in the Revenues and Expenses for the three months
         ended June 30, 2003 and 2002, respectively, for PECO.



                                       37
<PAGE>


     Six Months Ended June 30, 2003 and 2002, June 30, 2003, and December 31,
2002

<TABLE>
<CAPTION>

                                                                                       Corporate and
                                          Energy                                        Intersegment
                                        Delivery     Generation      Enterprises        Eliminations       Consolidated
------------------------------------------------------------------------------------------------------------------------
     Total Revenues (1):
<S>  <C>                              <C>            <C>             <C>              <C>                  <C>
     2003                             $    4,964     $    3,765      $      1,022     $       (1,956)      $      7,795
     2002                                  4,811          3,020               966             (1,921)             6,876
     Intersegment Revenues:
     2003                             $       35     $    1,889      $         35     $       (1,959)      $         --
     2002                                     29          1,845                47             (1,921)                --
     Income (Loss) Before Income Taxes and the Cumulative Effect of Changes in Accounting Principles:
     2003                             $      998     $      160      $       (125)    $          (42)      $        991
     2002                                    864            246                95                (56)             1,149
     Income Taxes:
     2003                             $      382     $       71      $        (47)    $          (36)      $        370
     2002                                    326             96                40                (35)               427
     Cumulative Effect of Changes in Accounting Principles:
     2003                             $        5     $      108      $         (1)    $           --       $        112
     2002                                     --             13              (243)                --               (230)
     Net Income (Loss):
     2003                             $      621     $      197      $        (79)    $           (6)      $        733
     2002                                    538            163              (188)               (21)               492
     Total Assets:
     June 30, 2003                    $   27,349     $   13,913      $      1,166     $       (2,140)      $     40,288
     December 31, 2002                    26,550         11,007             1,297             (1,369)            37,485
------------------------------------------------------------------------------------------------------------------------
</TABLE>

      (1) $113 million and $114 million in utility taxes are included in the
          Revenues and Expenses for the six months ended June 30, 2003 and 2002,
          respectively, for ComEd. $98 million and $93 million in utility taxes
          are included in the Revenues and Expenses for the six months ended
          June 30, 2003 and 2002, respectively, for PECO.


     7.   FAIR VALUE OF FINANCIAL ASSETS AND LIABILITIES (Exelon, ComEd,
          PECO and Generation)

               During  the three and six months  ended  June 30,  2003 and 2002,
     Exelon  recorded  pre-tax  gains  (losses)  in other  comprehensive  income
     relating to  mark-to-market  (MTM)  adjustments of contracts  designated as
     cash flow hedges as follows:

<TABLE>
<CAPTION>


                                                           ComEd         PECO      Generation  Enterprises      Exelon
------------------------------------------------------------------------------------------------------------------------
<S>                                                    <C>            <C>            <C>           <C>         <C>
     Three months ended June 30, 2003                  $      (6)     $     2        $    103      $     3     $    102
     Three months ended June 30, 2002                        (14)          (6)             10           (3)         (13)
     Six months ended June 30, 2003                           (5)           5            (191)           7         (184)
     Six months ended June 30, 2002                          (16)          (1)           (108)          14         (111)
------------------------------------------------------------------------------------------------------------------------
</TABLE>


                                       38
<PAGE>


              During  the three and six  months  ended  June 30,  2003 and 2002,
     Generation  recognized  net MTM  gains  on  non-trading  energy  derivative
     contracts  not  designated  as cash  flow  hedges,  in  purchased  power as
     follows:

                                                             2003         2002
--------------------------------------------------------------------------------
     Three months ended June 30,                          $    32     $      4
     Six months ended June 30,                                  1           10
--------------------------------------------------------------------------------

              During  the three and six  months  ended  June 30,  2003 and 2002,
     Generation  recognized net MTM losses on proprietary  trading  contracts in
     operating revenues as follows:

                                                             2003         2002
--------------------------------------------------------------------------------
     Three months ended June 30,                          $    (2)     $    (9)
     Six months ended June 30,                                 (4)         (13)
--------------------------------------------------------------------------------

               During the three and six months ended June 30, 2003 and 2002,  no
     amounts were reclassified to other income in the Consolidated Statements of
     Income and Comprehensive  Income as a result of the  discontinuance of cash
     flow hedges related to certain forecasted financing  transactions that were
     no longer probable of occurring.

               During  the three and six months  ended  June 30,  2003 and 2002,
     Generation  did  not  reclassify   any  amounts  from   accumulated   other
     comprehensive  income  into  earnings  as a  result  of  forecasted  energy
     commodity transactions no longer being probable.

               As of June 30, 2003,  deferred net gains  (losses) on  derivative
     instruments  accumulated in other comprehensive income that are expected to
     be reclassified to earnings during the next twelve months are as follows:
<TABLE>
<CAPTION>


                                                             ComEd      PECO   Generation   Enterprises    Exelon
------------------------------------------------------------------------------------------------------------------
<S>                                                        <C>        <C>        <C>            <C>     <C>
     Net gains (losses) expected to be reclassified        $    --    $   11     $   (281)      $   8   $   (262)
------------------------------------------------------------------------------------------------------------------
</TABLE>


               Amounts in  accumulated  other  comprehensive  income  related to
     interest  rate cash flow hedges are  reclassified  into  earnings  when the
     forecasted   interest   payment  occurs.   Amounts  in  accumulated   other
     comprehensive   income   related  to  energy   commodity   cash  flows  are
     reclassified  into  earnings  when the  forecasted  purchase or sale of the
     energy commodity occurs.

               As of June 30, 2003,  ComEd  expects to amortize  during the next
     twelve months $7 million of regulatory  assets for settled cash flow swaps.
     During  the three  and six  months  ended  June 30,  2003 and  2002,  ComEd
     reclassified  amounts from other comprehensive  income to regulatory assets
     for cash flow swaps settled as follows:

<TABLE>
<CAPTION>
                                                                                   2003         2002
------------------------------------------------------------------------------------------------------
<S>                          <C>                <C>    <C>                      <C>        <C>
     Three months ended June 30, (net of tax of $0 and $0, respectively)        $    --    $     1
     Six months ended June 30, (net of tax of $21 and $4, respectively)              30          6
------------------------------------------------------------------------------------------------------
</TABLE>


               ComEd has entered into interest rate swaps to effectively convert
     $485 million in  fixed-rate  debt to floating  rate debt.  These swaps have
     been  designated  as  fair-value  hedges as defined in SFAS No. 133, and as
     such,  changes in the fair value of the swaps will be recorded in



                                       39
<PAGE>


     earnings.  However, as long as the hedge remains effective,  changes in the
     fair  value of the swaps will be offset by changes in the fair value of the
     hedged  liabilities.  Any change in the fair value of the hedge as a result
     of ineffectiveness  would be recorded  immediately in earnings.  As of June
     30, 2003,  these swaps had an  aggregate  fair market value of $46 million,
     which was classified as other  deferred  debits and other assets within the
     Consolidated Balance Sheets.

               In 2003, ComEd entered into forward-starting  interest rate swaps
     with an aggregate  notional  amount of $440 million to manage interest rate
     exposure associated with anticipated debt issuance.  In connection with the
     2003 issuances of certain First Mortgage Bonds,  forward-starting  interest
     rate swaps with an aggregate  notional  amount of $870 million were settled
     with net  proceeds to  counterparties  of $51 million ($30  million,  after
     income  taxes)  that has been  deferred in  regulatory  assets and is being
     amortized  over the life of the  First  Mortgage  Bonds as an  increase  to
     interest expense.  See Note 9 - Long-Term Debt and Preferred Securities for
     additional  information regarding the issuance of the First Mortgage Bonds.
     On June 30, 2003, ComEd's remaining forward-starting swaps had an aggregate
     notional  amount of $200 million and an  aggregate  fair market value of $6
     million.

               PECO has entered into interest rate swaps to manage interest rate
     exposure  associated  with the  floating  rate series of  transition  bonds
     issued to securitize PECO's stranded cost recovery. At June 30, 2003, these
     interest  rate swaps had an  aggregate  fair market  value  exposure of $17
     million  based on the present  value  difference  between the  contract and
     market rates at June 30, 2003.

               In 2003, PECO entered into  forward-starting  interest rate swaps
     with an aggregate  notional  amount of $360 million to manage interest rate
     exposure  associated with an anticipated debt issuance.  In connection with
     the April 28, 2003 issuance of $450 million in First and Refunding Mortgage
     Bonds, PECO settled the swaps for net proceeds of $1 million (before income
     taxes),  which was  recorded  in other  comprehensive  income  and is being
     amortized over the life of the debt  issuance.  See Note 9 - Long-Term Debt
     and Preferred Securities for additional  information regarding the issuance
     of the First and Refunding Mortgage Bonds.

               Under  the  terms  of  the  EBG  Facility,  EBG  is  required  to
     effectively  fix the interest rate on 50% of borrowings  under the facility
     through its  maturity in 2007.  As of June 30,  2003,  EBG has entered into
     interest rate swap agreements,  which have  effectively  fixed the interest
     rate on  $861  million  of  notional  principal,  or  approximately  80% of
     borrowings  outstanding  under the EBG Facility at June 30, 2003.  The fair
     market value  exposure of these swaps,  designated as cash flow hedges,  is
     $105 million.

               Generation  has also  entered  into  interest  rate swaps with an
     aggregate notional amount of $200 million to manage interest rate exposures
     associated with an anticipated  debt issuance.  As of June 30, 2003,  these
     swaps had an aggregate fair market value of $4 million based on the present
     value  difference  between the  contract and market rates at June 30, 2003,
     which was  classified  as  deferred  debits  and other  assets  within  the
     Consolidated Balance Sheets.


                                       40
<PAGE>


               Generation  classifies  investments  in the  trust  accounts  for
     decommissioning nuclear plants as available-for-sale.  The following tables
     show the fair values,  gross unrealized gains and losses and amortized cost
     bases for the securities held in these trust accounts.

<TABLE>
<CAPTION>


                                                                                                          June 30, 2003
-----------------------------------------------------------------------------------------------------------------------
                                                                               Gross            Gross
                                                         Amortized        Unrealized       Unrealized         Estimated
                                                              Cost             Gains           Losses        Fair Value
-----------------------------------------------------------------------------------------------------------------------
<S>                                                       <C>              <C>               <C>                 <C>
     Cash and cash equivalents                            $    171         $      --         $     --            $  171
     Equity securities                                       1,909               124             (387)            1,646
     Debt securities
        Government obligations                               1,015                71               (2)            1,084
        Other debt securities                                  410                32              (27)              415
-----------------------------------------------------------------------------------------------------------------------
     Total debt securities                                   1,425               103              (29)            1,499
-----------------------------------------------------------------------------------------------------------------------
     Total available-for-sale securities                  $  3,505         $     227         $   (416)      $     3,316
=======================================================================================================================

                                                                                                      December 31, 2002
-----------------------------------------------------------------------------------------------------------------------
                                                                               Gross            Gross
                                                         Amortized        Unrealized       Unrealized         Estimated
                                                              Cost             Gains           Losses        Fair Value
-----------------------------------------------------------------------------------------------------------------------
     Cash and cash equivalents                            $    184         $      --         $     --            $  184
     Equity securities                                       1,763                72             (482)            1,353
     Debt securities
        Government obligations                                 938                62               --             1,000
        Other debt securities                                  514                32              (30)              516
-----------------------------------------------------------------------------------------------------------------------
     Total debt securities                                   1,452                94              (30)            1,516
-----------------------------------------------------------------------------------------------------------------------
     Total available-for-sale securities                  $  3,399         $     166         $   (512)         $  3,053
=======================================================================================================================
</TABLE>


               Net  unrealized   losses  of  $189  million  were  recognized  in
     regulatory   assets,    regulatory   liabilities   or   accumulated   other
     comprehensive  income in Exelon's  Consolidated  Balance  Sheet at June 30,
     2003. Net unrealized  losses of $189 million were  recognized in noncurrent
     affiliate payables,  noncurrent affiliate  receivables or accumulated other
     comprehensive income in Generation's  Consolidated Balance Sheet as of June
     30,  2003.  Net  unrealized  losses  of $346  million  were  recognized  in
     accumulated  depreciation and accumulated other comprehensive income in the
     Consolidated Balance Sheets of Exelon and Generation at December 31, 2002.

               During  the three and six months  ended  June 30,  2003 and 2002,
     proceeds  from the sale of  decommissioning  trust  investments  and  gross
     realized gains and losses on those sales were as follows:

<TABLE>
<CAPTION>


                                              Three Months Ended June 30,      Six Months Ended June 30,
                                              --------------------------       -------------------------
                                                        2003         2002              2003         2002
--------------------------------------------------------------------------------------------------------
<S>                                              <C>             <C>              <C>           <C>
     Proceeds from sales                         $       690     $    309         $   1,262     $    889
     Gross realized gains                                 51           13                65           31
     Gross realized losses                               (45)         (24)              (53)         (56)
--------------------------------------------------------------------------------------------------------

</TABLE>


               Net realized  gains of $6 million and net realized  losses of $11
     million for the three  months  ended June 30, 2003 and 2002,  respectively,
     were  recorded in other income and  deductions.  Net realized  gains of $12
     million and net  realized  losses of $21  million for the six months  ended
     June 30, 2003 and 2002,  respectively,  were  recorded in other  income and



                                       41
<PAGE>

     deductions.   Net  realized   losses  of  $4  million  were  recognized  in
     accumulated   depreciation   at  June  30,  2002.  The   available-for-sale
     securities  held at June 30, 2003 have an average  maturity of eight to ten
     years. The cost of these securities was determined on the basis of specific
     identification.


     8. COMMITMENTS AND CONTINGENCIES (Exelon, ComEd, PECO and Generation)

               For   information   regarding   capital   commitments,    nuclear
     decommissioning   and  spent  fuel  storage,   see  the   Commitments   and
     Contingencies and Nuclear  Decommissioning  and Spent Fuel Storage Notes in
     the Notes to Consolidated  Financial Statements of Exelon,  ComEd, PECO and
     Generation  for  the  year  ended  December  31,  2002.  See  Note  2 - New
     Accounting  Principles  and  Accounting  Changes for further  discussion of
     nuclear decommissioning commitments and contingencies.

     Environmental Liabilities

               As of  June  30,  2003,  Exelon  had  accrued  $131  million  for
     environmental  investigation  and  remediation  costs that currently can be
     reasonably  estimated,  including $108 million for  manufactured  gas plant
     (MGP)  investigation and remediation.  Exelon has identified 71 sites where
     former  MGP   activities   have  or  may  have   resulted  in  actual  site
     contamination.

               As  of  June  30,  2003,   ComEd  had  accrued  $86  million  for
     environmental  investigation  and  remediation  costs that currently can be
     reasonably  estimated.  This reserve included $82 million  (discounted) for
     MGP investigation and remediation.

               As of June 30, 2003, PECO had accrued $35 million  (undiscounted)
     for environmental investigation and remediation costs that currently can be
     reasonably  estimated,  including  $26  million for MGP  investigation  and
     remediation.  Pursuant  to a PUC  order,  PECO is  currently  recovering  a
     provision for environmental  costs annually for the remediation of sites of
     former MGP facilities,  for which PECO has recorded a regulatory asset (see
     Note 12 - Supplemental Financial Information).

               As  of  June  30,  2003,   Generation  had  accrued  $10  million
     (undiscounted)  for environmental  investigation and remediation cost, none
     of which relates to MGP investigation and remediation.

               Exelon,  ComEd,  PECO and Generation cannot predict the extent to
     which  they  will  incur  other  significant   liabilities  for  additional
     investigation and remediation costs at these or additional sites identified
     by  environmental  agencies  or  others,  or  whether  such  costs  may  be
     recoverable from third parties.

     Energy Commitments

               Exelon and  Generation  had long-term  commitments as of June 30,
     2003  relating  to the net  purchase  and  sale  of  energy,  capacity  and
     transmission   rights  from  unaffiliated   utilities,


                                       42
<PAGE>


     including  Midwest  Generation,  LLC  (Midwest  Generation),   and  others,
     including AmerGen, as expressed in the following table:
<TABLE>
<CAPTION>


                                                                         Power Only Purchases from
                           Net Capacity            Power Only            -------------------------      Transmission Rights
                           Purchases (1)     Non-Affiliate Sales        AmerGen(2) Non-Affiliates         Purchases (3)
------------------------------------------------------------------------------------------------------------------------------
<S>           <C>           <C>                     <C>                 <C>             <C>                 <C>
              2003          $  531                  $2,012              $  231          $1,306              $   38
              2004             822                   1,708                 492           1,066                 103
              2005             509                     536                 386             296                  84
              2006             476                     169                 398             223                   3
              2007             458                      61                 404             212                  --
              Thereafter     3,802                       1               1,826             845                  --
------------------------------------------------------------------------------------------------------------------------------
             Total          $6,598                  $4,487              $3,737          $3,948              $  228
==============================================================================================================================

</TABLE>

(1)       Net Capacity Purchases includes Midwest Generation commitments as of
          June 30, 2003. In 2003, Generation will take 1,778 MWs of option
          capacity under the Collins and Peaking Unit Agreements as well as
          1,265 MWs of optional capacity under the Coal Generation PPA. On June
          25, 2003, Generation notified Midwest Generation of its exercise of
          its call option under the Coal Generation PPA for 2004. Generation
          exercised its call option on 687 MWs of capacity for 2004 generated by
          Waukegan Unit 8 and Fisk Unit 19 and did not exercise its option on
          578 MWs of capacity at Waukegan Unit 6, Crawford Unit 7, and Will
          County Unit 3. Net Capacity Purchases in 2004 include 3,474 MWs of
          optional capacity from Midwest Generation. Net Capacity Purchases also
          include capacity sales to TXU under the PPA entered into in connection
          with the purchase of two generating plants in April 2002, which states
          that TXU will purchase the plant output from May through September
          from 2002 through 2006. The combined capacity of the two plants is
          2,334 MWs.
(2)       Generation has entered into PPAs dated June 26, 2003, December 18,
          2001, and November 22, 1999 with AmerGen. Generation has agreed to
          purchase 100% of the energy generated by Oyster Creek Nuclear Power
          Station (Oyster Creek) through April 9, 2009. Generation has agreed to
          purchase all the energy from Unit No. 1 at Three Mile Island Nuclear
          Station from January 1, 2002 through December 31, 2014. Generation has
          agreed to purchase all of the residual energy from Clinton Nuclear
          Power Station (Clinton) not sold to Illinois Power through December
          31, 2004. Currently, the residual output is approximately 31% of the
          total output of Clinton, but will increase to 100% and the obligation
          will continue until the Clinton NRC license expires in 2026.
(3)       Transmission Rights Purchases include estimated commitments in 2004
          and 2005 for additional transmission rights that will be required to
          fulfill firm sales contracts.

              Additionally, Generation has the following energy commitments:

               In connection with the 2001 corporate  restructuring,  Generation
     entered into a PPA with ComEd under which  Generation  has agreed to supply
     all of ComEd's load requirements  through 2004. Prices for this energy vary
     depending upon the time of day and month of delivery. During 2005 and 2006,
     ComEd's  PPA is a partial  requirements  agreement  under  which ComEd will
     purchase all of its required energy and capacity from Generation, up to the
     available capacity of the nuclear generating plants formerly owned by ComEd
     and  transferred to Generation.  Under the terms of the PPA,  Generation is
     responsible  for obtaining any required  transmission  service,  subject to
     ComEd's obligation to obtain network service over the ComEd system. The PPA
     also  specifies  that  prior to 2005,  ComEd and  Generation  will  jointly
     determine and agree on a market-based  price for energy delivered under the
     PPA for 2005 and 2006, which is expected to exceed current pricing.  In the
     event that the parties  cannot  agree to  market-based  prices for 2005 and
     2006 prior to July 1, 2004,  ComEd has the  option of  terminating  the PPA
     effective  December  31,  2004.  ComEd will  obtain any  additional  supply
     required from market sources in 2005 and 2006, and subsequent to 2006, will
     obtain  all  of  its  supply  from  market  sources,  which  could  include
     Generation.  The  PPA  for  2005  and  2006  may  be  extended  to  a  full
     requirements contract as a result of the Agreement (see Note 4 - Regulatory
     Issues).

               In connection with the 2001 corporate  restructuring,  Generation
     entered  into a PPA with PECO under which  Generation  has agreed to supply
     PECO with  substantially  all of PECO's electric supply needs through 2010.
     Also,  under the  restructuring,  PECO assigned its rights and  obligations
     under  various PPAs and fuel supply  agreements to  Generation.  Generation
     supplies power to PECO from the  transferred  generation  assets,  assigned
     PPAs and other market sources.

               Under terms of the 2001 corporate restructuring,  ComEd remits to
     Generation    any   amounts    collected   from   customers   for   nuclear
     decommissioning,   currently  totaling  $73  million  per  year.  Under  an
     agreement  effective  September 2001, PECO remits to Generation any amounts
     collected from customers for nuclear  decommissioning,  currently  totaling
     $29 million per year. See Note 2 - New Accounting Principles and Accounting
     Changes for further  discussion  of the impact of the  adoption of SFAS No.
     143 on these collections.

     Litigation

     Exelon

               Securities  Litigation.  Between May 8 and June 14, 2002, several
     class action  lawsuits were filed in the Federal  District Court in Chicago
     asserting nearly identical securities law claims on behalf of purchasers of
     Exelon  securities  between  April 24, 2001 and  September  27, 2001 (Class
     Period). The complaints allege that Exelon violated Federal securities laws
     by issuing a series of materially false and misleading  statements relating
     to its 2001  earnings  expectations  during  the  Class  Period.  The court
     consolidated  the pending  cases into one lawsuit  and  appointed  two lead
     plaintiffs as well as lead counsel.

               On October 1, 2002, the plaintiffs  filed a consolidated  amended
     complaint,  which  contained  allegations  of new  facts  and  several  new
     theories of liability.  On June 13, 2003,  the court  dismissed the amended
     complaint  with  prejudice.  The  plaintiffs  have agreed not to appeal the
     court's order of dismissal, thereby terminating the case.

     ComEd

               FERC  Municipal  Request for Refund.  Three of ComEd's  wholesale
     municipal  customers  filed a  complaint  and  request  for refund with the
     Federal Energy Regulatory Commission (FERC),  alleging that ComEd failed to
     properly  adjust its rates, as provided for under the terms of the electric
     service contracts with the municipal customers and to track certain refunds
     made to ComEd's retail  customers in the years 1992 through 1994. ComEd and
     the municipal  customers  have executed a settlement  agreement  ending the
     litigation.  Under the settlement,  ComEd will pay a total of approximately
     $3 million to the three municipalities.

               Retail  Rate Law.  In 1996,  several  developers  of  non-utility
     generating  facilities filed litigation  against various Illinois officials
     claiming that the enforcement  against those  facilities of an amendment to
     Illinois   law   removing   the   entitlement   of  those   facilities   to
     state-subsidized  payments  for  electricity  sold to ComEd after March 15,
     1996 violated their rights under the Federal and state  constitutions.  The
     developers  also filed suit against ComEd for a  declaratory  judgment that
     their  rights  under their  contracts  with ComEd were not  affected by the
     amendment  and for breach of  contract.  On November  25,  2002,  the court
     granted  the  developers'  motions  for  summary  judgment.  The judge also
     entered a permanent  injunction  enjoining  ComEd from  refusing to pay the
     retail rate on the grounds of the  amendment,  and  Illinois  from  denying



                                       44
<PAGE>

     ComEd a tax credit on account of such  purchases.  ComEd and Illinois  have
     each  appealed  the  ruling.  ComEd  believes  that it did not  breach  the
     contracts in question and that the damages claimed far exceed any loss that
     any project  incurred  by reason of its  ineligibility  for the  subsidized
     rate.   ComEd  intends  to  prosecute  its  appeal  and  defend  each  case
     vigorously.

               Service  Interruptions.   In  August  1999,  three  class  action
     lawsuits were filed against ComEd,  and subsequently  consolidated,  in the
     Circuit  Court  of Cook  County,  Illinois  seeking  damages  for  personal
     injuries,  property  damage  and  economic  losses  related  to a series of
     service  interruptions  that  occurred in the summer of 1999.  The combined
     effect of these  interruptions  resulted in over 168,000  customers  losing
     service  for more than four hours.  The court  approved  conditional  class
     certification for the sole purpose of exploring  settlement.  ComEd filed a
     motion to dismiss the  complaints.  On April 24, 2001, the court  dismissed
     four of the five counts of the consolidated complaint without prejudice and
     the sole  remaining  count was  dismissed  in part.  On June 1,  2001,  the
     plaintiffs  filed a second  amended  consolidated  complaint  and ComEd has
     filed an answer.  On December 5, 2002,  a settlement  was reached,  whereby
     ComEd will pay up to $8 million,  which  includes $4 million  paid to date.
     The Court  preliminarily  approved the  settlement on June 23, 2003,  and a
     final hearing is set for October 2, 2003.  The  settlement,  when approved,
     will release ComEd from all claims arising from the 1999 power  outages.  A
     portion of any settlement or verdict may be covered by insurance.

     Generation

               Cotter Corporation Litigation. During 1989 and 1991, actions were
     brought in  Federal  and state  courts in  Colorado  against  ComEd and its
     subsidiary,  Cotter Corporation  (Cotter),  seeking unspecified damages and
     injunctive  relief based on allegations that Cotter  permitted  radioactive
     and other hazardous  material to be released from its mill into areas owned
     or occupied by the  plaintiffs,  resulting in property damage and potential
     adverse  health  effects.  In 1994, a Federal jury returned  nominal dollar
     verdicts  against  Cotter on eight  plaintiffs'  claims in the 1989  cases,
     which  verdicts  were upheld on appeal.  The  remaining  claims in the 1989
     actions  were  settled or  dismissed.  In 1998, a jury verdict was rendered
     against Cotter in favor of 14 of the plaintiffs in the 1991 cases, totaling
     approximately $6 million in compensatory and punitive damages, interest and
     medical monitoring.  On appeal, the Tenth Circuit Court of Appeals reversed
     the jury verdict,  and remanded the case for new trial.  These  plaintiffs'
     cases were consolidated with the remaining 26 plaintiffs'  cases, which had
     not been tried. The consolidated  trial was completed on June 28, 2001. The
     jury returned a verdict  against  Cotter and awarded $16 million in various
     damages.  On November 20, 2001, the District Court entered an amended final
     judgment  that  included an award of both  pre-judgment  and  post-judgment
     interests,  costs, and medical monitoring  expenses that total $43 million.
     In  November  2000,  another  trial  involving a separate  sub-group  of 13
     plaintiffs,  seeking $19 million in damages plus  interest was completed in
     Federal  District  Court in Denver.  The jury  awarded  nominal  damages of
     $42,500 to 11 of 13  plaintiffs,  but awarded no damages  for any  personal
     injury or health claims,  other than requiring  Cotter to perform  periodic
     medical  monitoring at minimal cost. Cotter appealed these judgments to the
     Tenth Circuit Court of Appeals.  On April 22, 2003, the Tenth Circuit Court
     of Appeals  reversed  both  judgments  and  remanded the cases for retrial.
     Cotter intends to vigorously defend each case.

               On February 18, 2000, ComEd sold Cotter to an unaffiliated  third
     party.  As part of the


                                       45
<PAGE>


     sale, ComEd agreed to indemnify Cotter for any liability incurred by Cotter
     as a  result  of  these  actions,  as  well  as any  liability  arising  in
     connection with the West Lake Landfill discussed in the next paragraph.  In
     connection with Exelon's 2001 corporate  restructuring,  the responsibility
     to  indemnify  Cotter  for any  liability  related  to  these  matters  was
     transferred by ComEd to Generation.

               The U.S. Environmental Protection Agency (EPA) has advised Cotter
     that it is potentially liable in connection with radiological contamination
     at a site known as the West Lake Landfill in Missouri. Cotter is alleged to
     have disposed of  approximately  39,000 tons of soils mixed with 8,700 tons
     of leached  barium  sulfate  at the site.  Cotter,  along with three  other
     companies identified by the EPA as potentially  responsible parties (PRPs),
     has submitted a draft feasibility study addressing  options for remediation
     of the site.  The PRPs are also  engaged in  discussions  with the State of
     Missouri and the EPA. The estimated costs of remediation for the site range
     from $0 to $87 million.  Once a remedy is selected, it is expected that the
     PRPs will agree on an allocation of responsibility  for the costs. Until an
     agreement is reached, Generation cannot predict its share of the costs.

               Raytheon  Arbitration.  In March 2001, two  subsidiaries of Sithe
     New England  acquired in November  2002,  brought an action in the New York
     Supreme  Court  against  Raytheon  Corporation  (Raytheon)  relating to its
     failure to honor its guaranty with respect to the performance of the Mystic
     and Fore River projects,  as a result of the abandonment of the projects by
     the turnkey  contractor.  In a related  proceeding,  in May 2002,  Raytheon
     submitted  claims  to  the  International  Chamber  of  Commerce  Court  of
     Arbitration  (Arbitration  Court) seeking  equitable relief and damages for
     alleged  owner-caused  performance delays in connection with the Fore River
     Power  Plant  Engineering,   Procurement  &  Construction   Agreement  (EPC
     Agreement).  The EPC  Agreement,  executed  by a  Raytheon  subsidiary  and
     guaranteed  by  Raytheon,  governs the design,  engineering,  construction,
     start-up,  testing and delivery of an 800-MW  combined-cycle power plant in
     Weymouth, Massachusetts.  Hearings by the Arbitration Court with respect to
     liability  were held in January and February  2003.  On May 12,  2003,  the
     Arbitration  Court issued an Interim  Order finding in favor of Raytheon on
     liability, but limited the grounds upon which Raytheon could claim schedule
     and cost relief.  After the Interim  Order,  Raytheon  amended its claim to
     seek 110 days of schedule relief (which would reduce Raytheon's  liquidated
     damage  payment  for  late  delivery  by  approximately  $20  million)  and
     additional  damages of $12 million.  Raytheon  also has asserted a claim in
     the  amount  of  approximately  $13  million  for  loss of  efficiency  and
     productivity  as a result  of an  alleged  constructive  acceleration.  The
     aggregate  amount  of  Raytheon's  asserted  claims  is  approximately  $45
     million,  not  including  general  and  administrative  costs,  profit  and
     interest that Raytheon asserts are due under the contract.  Hearings by the
     Arbitration  Court  with  respect  to  damages  are  scheduled  and a final
     decision is expected in September 2003.  Generation believes that Sithe New
     England properly  rejected  Raytheon's  request for a change order and that
     Raytheon's damages claims are inflated. In addition to its asserted claims,
     Raytheon has indicated  that it will bring  additional  claims for damages.
     Exelon will continue to vigorously  defend its position in the  arbitration
     and contest any additional claims that may be asserted.


                                       46
<PAGE>


               Clean Air Act. On June 1, 2001, the EPA issued to EBG a Notice of
     Violation (NOV) and Reporting  Requirement pursuant to Sections 113 and 114
     of the Clean Air Act, alleging  numerous  exceedances of opacity limits and
     violations   of   opacity-related   monitoring,   recording  and  reporting
     requirements  at Mystic  Station in Everett,  Massachusetts.  On January 8,
     2002,  the EPA indicated  that it had decided to resolve the NOV through an
     administrative  compliance  order and a judicial civil penalty  action.  In
     March 2002, the EPA issued and Sithe Mystic LLC, a wholly owned  subsidiary
     of EBG,  voluntarily  entered a Compliance Order and Reporting  Requirement
     (Compliance  Order)  regarding  Mystic Station,  under which Mystic Station
     installed  new ignition  equipment on three of the four units at the plant.
     Mystic Station also undertook an extensive  opacity  monitoring and testing
     program  for all four units at the plant to help  determine  if  additional
     compliance  measures  were  needed.  Pursuant  to the  requirements  of the
     Compliance  Order,  EBG switched  three of the four units to a lower sulfur
     fuel oil by September 1, 2002. The Compliance  Order does not address civil
     penalties.  By a letter dated April 21, 2003, the United States  Department
     of Justice  notified  EBG that,  at the  request of the EPA, it intended to
     bring a civil penalty  action,  but also offered the opportunity to resolve
     the matter  through  settlement  discussions.  EBG is  pursuing  settlement
     discussions with the EPA and the Department of Justice.

               Real Estate Tax  Appeals.  Generation  is involved in tax appeals
     regarding a number of its nuclear  facilities,  Limerick Generating Station
     (Montgomery  County,  PA),  Peach Bottom Atomic Power Station (York County,
     PA) and Quad Cities  Station (Rock Island County,  IL).  Generation is also
     involved  in the tax appeal  for Three Mile  Island  (Dauphin  County,  PA)
     through  AmerGen.  Generation does not believe the outcome of these matters
     will have a material  adverse effect on Generation's  results of operations
     or financial condition.

     Exelon, ComEd, PECO and Generation

               Exelon,  ComEd, PECO and Generation are involved in various other
     litigation  matters.  The ultimate outcome of such matters,  as well as the
     matters  discussed  above,  while  uncertain,  are not  expected  to have a
     material adverse effect on their respective  financial condition or results
     of operations.




                                       47
<PAGE>


     Commercial Commitments

               Exelon, ComEd, PECO and Generation's commercial commitments as of
     June 30, 2003,  representing  commitments not recorded on the balance sheet
     but potentially  triggered by future events,  including obligations to make
     payment on behalf of other  parties and  financing  arrangements  to secure
     their obligations, are as follows:

<TABLE>
<CAPTION>


                                                                                                      Expiration within
                                                -----------------------------------------------------------------------
                                                                                                                   2008
     Exelon                                     Total         2003        2004-2005         2006-2007        and beyond
-----------------------------------------------------------------------------------------------------------------------
     Related to Obligations Recorded on the Balance Sheet
---------------------------------------------------------

<S>                                        <C>            <C>             <C>                <C>                  <C>
     Credit Facility (a)                   $    1,500     $  1,500        $      --          $     --             $  --
     Letters of Credit (non-debt) (b)             119           45               74                --                --
     Letters of Credit (long-term debt) (c)       456          158              298                --                --
     Preferred Securities Guarantee (d, e)        528           --               --                --               528
     Guarantees of Long-Term Debt (f)              41           --                2                --                39
     Midwest Generation Capacity
       Reservation Agreement Guarantee (g)         34            2                7                 7                18
     Other
     -----
     Guarantees of Letters of Credit (h)           93           77               16                --                --
     Performance Guarantees (i)                   101           --               --                --               101
     Surety Bonds (j)                             681          241              286                 3               151
     Energy Marketing Contract
        Guarantees (k)                            207           92              115                --                --
     Nuclear Insurance Guarantees (l)           1,380           --               --                --             1,380
     Lease Guarantees (m)                          13           --               --                 2                11
     EBG Equity Guarantee (n)                      38           38               --                --                --
     Fuel purchase agreements (o)               2,169          308              690               637               534
-----------------------------------------------------------------------------------------------------------------------
     Total                                 $    7,360     $  2,461        $   1,488          $    649     $       2,762
=======================================================================================================================

                                                                                                      Expiration within
                                                -----------------------------------------------------------------------
                                                                                                                   2008
     ComEd                                      Total         2003        2004-2005         2006-2007        and beyond
-----------------------------------------------------------------------------------------------------------------------
     Related to Obligations Recorded on the Balance Sheet
     ----------------------------------------------------
     Credit Facility (a)                   $      100     $    100        $      --          $     --     $          --
     Letters of Credit (non-debt) (b)              23            4               19                --                --
     Letters of Credit (long-term debt) (c)        92           92               --                --                --
     Preferred Securities Guarantees (e)          350           --               --                --               350
     Midwest Generation Capacity
       Reservation Agreement Guarantee (g)         34            2                7                 7                18
     Other
     -----
     Surety Bonds (j)                              21           --                3                --                18
-----------------------------------------------------------------------------------------------------------------------
     Total                                 $      620     $    198        $      29          $      7            $  386
=======================================================================================================================



                                       48
<PAGE>


                                                                                                      Expiration within
                                                -----------------------------------------------------------------------
                                                                                                                   2008
     PECO                                       Total         2003        2004-2005         2006-2007        and beyond
-----------------------------------------------------------------------------------------------------------------------
     Related to Obligations Recorded on the Balance Sheet
     ----------------------------------------------------
     Credit Facility (a)                   $      400     $    400        $      --          $     --            $   --
     Letters of Credit (non-debt) (b)              31            1               30                --                --
     Preferred Securities Guarantees (d)          178           --               --                --               178
     Other
     -----
     Surety Bonds (j)                              45            1               44                --                --
----------------------------------------------------------------------------------------------------------------------
     Total                                 $      654     $    402        $      74          $     --            $  178
=======================================================================================================================

                                                                                                      Expiration within
                                                -----------------------------------------------------------------------
                                                                                                                   2008
     Generation                                 Total         2003        2004-2005         2006-2007        and beyond
----------------------------------------------------------------------------------------------------------------------
     Related to Obligations Recorded on the Balance Sheet
     ----------------------------------------------------
     Credit Facility (a)                   $       --     $     --        $      --          $     --     $          --
     Letters of Credit (non-debt) (b)              16            9                7                --                --
     Letters of Credit (long-term debt) (c)       364           66              298                --                --
     Other
     -----
     Guarantees of Letters of Credit (h)           66           66               --                --                --
     Performance Guarantees (i)                   101           --               --                --               101
     Surety Bonds (j)                              43           --               --                --                43
     Energy Marketing Contract
     Guarantees (k)                                24           24               --                --                --
     Nuclear Insurance Guarantee (p)              134           --               --                --               134
     EBG Equity Guarantee (n)                      38           38               --                --                --
     Fuel purchase agreements (o)               2,169          308              690               637               534
----------------------------------------------------------------------------------------------------------------------
     Total                                 $    2,955     $    511        $     995          $    637     $         812
=======================================================================================================================

</TABLE>

(a)         Credit Facility - Exelon, along with ComEd, PECO and Generation,
            maintain a $1.5 billion 364-day credit facility to support
            commercial paper issuances. At June 30, 2003, there were no
            borrowings against the credit facility. Additionally, at June 30,
            2003, commercial paper outstanding was as follows:
               Exelon Corporate         $     411
               ComEd                           --
               PECO                           170
               Generation                      --
(b)         Letters of Credit (non-debt) - Exelon and certain of its
            subsidiaries maintain non-debt letters of credit to provide credit
            support for certain transactions as requested by third parties.
(c)         Letters of Credit (long-term debt) - Direct-pay letters of credit
            issued in connection with variable-rate debt in order to provide
            liquidity in the event that it is not possible to remarket all of
            the debt as required following specific events, including changes in
            the basis of determining the interest rate on the debt.
(d)         Preferred Securities Guarantee - Guarantees issued to guarantee the
            preferred securities of the subsidiary trusts of PECO.
(e)         Preferred Securities Guarantees - Guarantees issued to guarantee the
            preferred securities of the subsidiary trusts of ComEd.
(f)         Guarantees of Long-Term Debt - Issued to guarantee payment of
            Enterprises' debt.
(g)         Midwest Generation  Capacity  Reservation  Agreement  Guarantee - In
            connection with ComEd's agreement with the City of Chicago (Chicago)
            entered into on February 20, 2003,  Midwest  Generation assumed from
            Chicago a Capacity  Reservation  Agreement  that Chicago had entered
            into with Calumet Energy Team, LLC. ComEd will reimburse Chicago for
            any   nonperformance  by  Midwest   Generation  under  the  Capacity
            Reservation Agreement. The fair value of this guarantee under FIN 45
            of $4 million  is  included  as a  liability  on Exelon and  ComEd's
            Consolidated Balance Sheets.  Additional  information regarding this
            liability  is  included   within  this  section  under  the  heading
            "General" below.
(h)         Guarantees of letters of credit - Guarantees issued to provide
            support for letters of credit as required by third parties. These
            guarantees could be called upon only in the event of non-payment by
            a subsidiary.
(i)         Performance Guarantees - Guarantees issued to ensure performance
            under specific contracts.
(j)         Surety Bonds - Guarantees  issued related to contract and commercial
            surety bonds, excluding bid bonds.



                                       49
<PAGE>

(k)         Energy Marketing Contract Guarantees - Guarantees issued to ensure
            performance under energy commodity contracts.
(l)         Nuclear Insurance Guarantees - Guarantees of nuclear insurance
            required under the Price-Anderson Act. $1.1 billion of this total
            exposure is exempt from the $4.5 billion PUHCA guarantee limit by
            SEC rule.
(m)         Lease Guarantees - Guarantees issued to ensure payments on building
            leases.
(n)         EBG Equity Guarantee- See Note 3 - Acquisitions, Dispositions and
            Retirements for further information on the $38 million guarantee.
            Pursuant to existing guarantees, after construction of the EBG
            facilities is complete, Exelon could be required to pay up to an
            additional $42 million relating to various construction and tax
            obligations.
(o)         Fuel Purchase Agreements - Commitments to purchase fuel supplies for
            nuclear generation.
(p)         Nuclear Insurance Guarantee - Guarantees of
            nuclear insurance required under the Price-Anderson
            Act. This amount relates to Generation's guarantee of AmerGen's
            plants. Exelon has a $1.2 billion guarantee relating to Generation's
            directly owned plants that is not included in this amount.

     Credit Contingencies

               Generation  is  a  counterparty   to  Dynegy  in  various  energy
     transactions.  In early  July  2002,  the  credit  ratings  of Dynegy  were
     downgraded to below investment  grade by two credit rating agencies.  As of
     June 30, 2003, Generation had a net receivable from Dynegy of approximately
     $4  million  and,   consistent  with  the  terms  of  the  existing  credit
     arrangement,  has  received  collateral  in  support  of  this  receivable.
     Generation also has credit risk associated with Dynegy through Generation's
     equity  investment  in  Sithe.  Sithe is a 60%  owner  of the  Independence
     generating station (Independence),  a 1,040-MW gas-fired qualified facility
     that has an energy-only  long-term  tolling  agreement with Dynegy,  with a
     related  financial  swap  arrangement.  As of  June  30,  2003,  Sithe  had
     recognized  an asset on its balance  sheet related to the fair market value
     of the financial  swap agreement with Dynegy that is marked to market under
     the terms of SFAS No. 133. If Dynegy is unable to fulfill the terms of this
     agreement,  Sithe would be required  to impair this  financial  swap asset.
     Generation estimates,  as a 49.9% owner of Sithe, that the impairment would
     result in an  after-tax  reduction  of its  earnings of  approximately  $17
     million.

               In addition to the  impairment  of the financial  swap asset,  if
     Dynegy were  unable to fulfill its  obligations  under the  financial  swap
     agreement  and the  tolling  agreement,  Generation  may  incur  a  further
     impairment associated with Independence.

               Additionally,  the future  economic  value of AmerGen's  PPA with
     Illinois Power Company, a subsidiary of Dynegy, could be impacted by events
     related to Dynegy's financial condition.

               In connection  with ComEd's sale of assets to Midwest  Generation
     prior to the  Merger,  ComEd  had  entered  into an Agency  Agreement  with
     Midwest Generation and certain of Midwest Generation's related parties (the
     "Guarantors")  whereby the Guarantors  assumed the benefits and liabilities
     of a coal  purchase  contract.  ComEd  remained  the  signatory to the coal
     contract,  and in connection with the Merger and subsequent  restructuring,
     Generation  assumed the  signatory  obligation on this contract from ComEd.
     Midwest  Generation's  credit  ratings have  recently  been  downgraded  by
     certain credit rating agencies.  In the event of Midwest Generation and the
     Guarantors  non-performance  under the coal purchase  contract,  Generation
     would be required to fulfill the purchase  commitments which extend through
     2012.  The  contract  requires  the  purchase of two  million  tons of coal
     annually,  or specifies a minimum payout. Based upon current market prices,
     Generation's contingent obligations for the contract years 2003 to 2012 are
     estimated  to be  approximately  $81  million  related  to this  agreement.
     Generation  and ComEd have  entered



                                       50
<PAGE>

     into other agreements with Midwest Generation in which the  non-performance
     by Midwest Generation is currently not anticipated to result in significant
     contingent obligations to Generation or ComEd.

     Spent Fuel Storage

              In connection with a July 2000 agreement between PECO and the U.S.
     Department  of Energy (DOE)  relating to the Peach Bottom  Station  Nuclear
     Waste Fund and interim  spent  nuclear fuel storage  costs,  Generation  is
     currently  in  discussions  with the DOE  regarding  possible  repayment of
     amounts  received as credits  against  contributions  to the Nuclear  Waste
     Fund. Based upon discussions with the DOE,  Generation  estimates the range
     of potential  liability to be $0 to $20 million,  excluding any  additional
     recoveries.  At June 30, 2003, based upon the status of the discussions and
     uncertainty  surrounding the amounts to be repaid,  if any, no amounts have
     been accrued.  See Note 9 - Nuclear  Decommissioning and Spent Nuclear Fuel
     Storage in Generation's  Form 10-K for the year ended December 31, 2002 for
     additional information regarding this matter.

     General

              On February 20, 2003, ComEd entered into separate  agreements with
     Chicago and with Midwest Generation (Midwest Agreement). Under the terms of
     the  agreement  with  Chicago,  ComEd will pay Chicago $60 million over ten
     years  ($6  million  was paid  during  the  first  quarter  of 2003) and be
     relieved of a requirement,  originally  transferred  to Midwest  Generation
     upon  the  sale of  ComEd's  fossil  stations  in  1999,  to build a 500-MW
     generation  facility.  Under the Midwest  Agreement,  ComEd  received  from
     Midwest  Generation  $22  million  during  the first  quarter  2003 and $10
     million during April 2003, to relieve Midwest Generation's obligation under
     the fossil sale agreement.  Midwest  Generation also assumed from Chicago a
     Capacity  Reservation  Agreement that Chicago had entered into with Calumet
     Energy  Team,  LLC (CET),  which is effective  through June 2012.  ComEd is
     obligated to reimburse Chicago for any nonperformance by Midwest Generation
     under the Capacity Reservation  Agreement and paid approximately $2 million
     for amounts owed to CET by Chicago at the time the  agreement was executed.
     In the first quarter of 2003,  ComEd  recorded a guarantee  liability of $4
     million  under the  provisions  of FIN No. 45 related to its  obligation to
     reimburse  Chicago for any  nonperformance by Midwest  Generation.  The net
     effect of the settlement to ComEd will be amortized over the remaining life
     of the franchise agreement with Chicago.

              ComEd and PECO have  entered into  several  agreements  with a tax
     consultant related to the filing of refund claims with the Internal Revenue
     Service  (IRS).  The  fees  for  these  agreements  are  contingent  upon a
     successful outcome and are based upon a percentage of the refunds recovered
     from the IRS, if any. As such,  ComEd and PECO would have positive net cash
     flows  related  to  these  agreements  if any  fees  are  paid  to the  tax
     consultant.  These  potential  tax  benefits and  associated  fees could be
     material to the financial position, results of operations and cash flows of
     ComEd and PECO.  ComEd's tax benefits for periods prior to the Merger would
     be recorded as a reduction of goodwill  pursuant to a  reallocation  of the
     Merger  purchase  price.  ComEd and PECO  cannot  predict the timing of the
     final resolution of these refund claims.


                                       51
<PAGE>


               In the second quarter of 2003,  Exelon progressed in its plans to
     implement its new business  model referred to as The Exelon Way. The Exelon
     Way is focused on improving  operating cash flows while meeting service and
     financial  commitments  through  improved  integration  of  operations  and
     consolidation of support functions.  Exelon is working to meet its goals of
     approximately  $300  million of annual cash  savings  beginning in 2004 and
     increasing  the annual cash savings to $600 million in 2006. As part of the
     implementation  of The Exelon Way, Exelon  anticipates  incurring  expenses
     associated  with the  rationalization  of certain  business  functions  and
     employee  separation  costs.  These  expenses  may be  significant  and are
     expected to be incurred  during the  remaining  half of 2003 through  2005.
     However, these costs cannot be reasonably estimated at this time.


9. LONG-TERM DEBT AND PREFERRED SECURITIES (Exelon, ComEd, PECO and Generation)

               On May 15, 2003,  ComEd redeemed $42 million of 5.875%  Pollution
     Control  Revenue  Bonds 1977 Series A, due May 15, 2007  originally  issued
     through the Illinois Industrial Pollution Control Financing Authority.

               On May 8, 2003,  ComEd  issued $40 million of  variable  interest
     Pollution  Control  Revenue  Refunding  Bonds due May 15, 2017  through the
     Illinois Development Finance Authority.

               On April 15,  2003,  ComEd  redeemed  $160  million  of its First
     Mortgage Bonds, at a redemption price of 103.664% of the principal  amount,
     plus accrued  interest.  The bonds,  which  carried an interest rate of 8%,
     were refinanced with long-term debt issued on April 7, 2003.

               On April 7,  2003,  ComEd  issued  $395  million  of 4.70%  First
     Mortgage  Bonds,  due on April 15,  2015.  The proceeds of these bonds were
     used to refund other First Mortgage Bonds.

               On March 20,  2003,  ComEd  redeemed  $200  million  of its trust
     preferred securities at a redemption price of 100% of the principal amount,
     plus accrued  distributions.  The  preferred  securities,  which carried an
     interest rate of 8.48%,  were refinanced with the proceeds from a March 17,
     2003 issue of $200  million  of trust  preferred  securities  which have an
     annual distribution rate of 6.35% and are mandatorily redeemable in 2033.

               On March 18,  2003,  ComEd  redeemed  $236  million  of its First
     Mortgage Bonds, at a redemption price of 103.863% of the principal  amount,
     plus accrued interest. The bonds, which carried an interest rate of 8.375%,
     were refinanced with long-term debt issued on April 7, 2003.

               On January 22,  2003,  ComEd  issued $350  million of 3.70% First
     Mortgage  Bonds,  due in 2008 and $350  million  of 5.875%  First  Mortgage
     Bonds, due in 2033.  These bond issuances were used to refinance  long-term
     debt that had been previously  retired during the third and fourth quarters
     of 2002.



                                       52
<PAGE>


               During  the six  months  ended  June 30,  2003,  Exelon and ComEd
     retired  $267 million and $52 million of  commercial  paper  classified  as
     long-term debt, respectively.

               During  the six  months  ended  June  30,  2003,  ComEd  recorded
     prepayment premiums of $15 million and net unamortized premiums,  discounts
     and debt  issuance  expenses  of $31  million,  associated  with the  early
     retirement  of debt in 2003 that have been  deferred by ComEd in regulatory
     assets  and will be  amortized  to  interest  expense  over the life of the
     related new debt issuance consistent with regulatory recovery.

               On June 24,  2003,  PECO issued $100  million of trust  preferred
     securities with an annual  distribution  rate of 5.75% that are mandatorily
     redeemable  in 2033.  These  securities  were  recorded as  liabilities  in
     accordance  with SFAS No. 150 (see Note 2 - New  Accounting  Principles and
     Accounting  Changes).  The  proceeds  of the issue  were used to redeem the
     trust preferred securities and preferred stock discussed below.

               Also on June 24,  2003,  PECO  redeemed  $50 million of its 8.00%
     trust preferred  securities at a redemption price of $25 per trust receipt,
     plus accrued and unpaid distributions.

               On  June  11,  2003,  PECO  redeemed  $50  million  of its  $7.48
     preferred  stock at a redemption  price of $103.74 per share,  plus accrued
     and unpaid dividends.

               On April 28,  2003,  PECO issued $450  million of 3.50% First and
     Refunding  Mortgage Bonds due on May 1, 2008. The proceeds from the sale of
     the bonds were used to repay  aggregate  principal of maturing  debt and to
     repay commercial paper that was used to refinance long-term debt.

               On June 13, 2003,  Generation  closed on a $550 million revolving
     credit facility.  Generation used the facility to make the first payment to
     Sithe  relating to the $536 million  note that was used to purchase  Exelon
     New England from Sithe.  This note was restructured in June 2003 to provide
     for a payment of $210  million of the  principal  on June 16,  2003 and the
     remaining  principal  on the  earlier  of  December  1,  2003 or  change of
     control.

               On June 3, 2003,  Generation  issued $17 million of variable rate
     Pollution  Control  Revenue  Refunding  Bonds,  Series  A, due June 1, 2027
     through the Indiana County Industrial Development  Authority.  The proceeds
     of these bonds were used to refund $17 million of Pollution Control Revenue
     Refunding Bonds, due June 1, 2027, issued on behalf of PECO.

               See Note 7 - Fair Value of Financial  Assets and  Liabilities for
     additional  information  regarding  interest rate swaps of ComEd,  PECO and
     Generation.


                                       53
<PAGE>



     10.  UNCONSOLIDATED INVESTMENTS (Exelon and Generation)

               During the three months ended June 30, 2003,  Exelon  recorded an
     impairment  charge of $35 million (before income taxes) in other income and
     deductions  within the Consolidated  Statements of Income and Comprehensive
     Income  related  to an  other-than-temporary  decline  in value of  certain
     investments  held by  Enterprises.  Management  of Exelon  and  Enterprises
     considered various factors in the decision to record an impairment of these
     investments,   including  recent   valuations  of  the  investments.   This
     impairment  reduced the book value of these investments from $42 million at
     December 31, 2002 to $7 million at June 30, 2003.

     Generation

               Generation  is a 49.9% owner of Sithe and has  accounted  for the
     investment as an unconsolidated equity investment through June 30, 2003. In
     the first  quarter of 2003,  Exelon and  Generation  recorded an impairment
     charge  of  $200  million   (before  income  taxes)  in  other  income  and
     deductions,  associated with a decline in the Sithe  investment fair value,
     which was considered to be other than  temporary.  Exelon and  Generation's
     management  considered  various  factors  in  the  decision  to  record  an
     impairment of this investment,  including management's recent experience of
     exploring the sale of its interest in Sithe.  The  discussions  surrounding
     the sale  indicated  that the fair value of the Sithe  investment was below
     its book value,  and as such, an impairment  charge was required.  The book
     value of  Generation's  investment  in Sithe was $209  million  at June 30,
     2003.  For the six months ended June 30,  2003,  Sithe had revenues of $356
     million. Generation recorded $1.6 million of equity method losses for Sithe
     for the six  months  ended  June  30,  2003.  See  Note 2 - New  Accounting
     Principles  and  Accounting  Changes for discussion of Sithe in relation to
     FIN No. 46.

               On May 29, 2003,  Exelon Fossil  Holdings,  Inc., a  wholly-owned
     subsidiary of Generation,  issued an irrevocable  call notice for the 35.2%
     interest in Sithe owned by Apollo Energy,  LLC and the 14.9% interest owned
     by subsidiaries of Marubeni Corporation.  The total call price was based on
     the terms of the  existing Put and Call  Agreement  (PCA) among the parties
     and approximated $650 million.  The transfer of ownership  requires various
     regulatory approvals, including FERC, the state environmental agency in New
     Jersey, and expiration of the Hart Scott Rodino waiting period.

               Under the terms of the PCA,  the call must be funded  within  six
     months of the call notice being issued.  Additionally,  because the Federal
     Power  Act  restricts  Exelon's  ownership  of 50% or  more  of  qualifying
     facilities,  the  qualifying  facilities  owned  by  Sithe  must be sold or
     restructured   before  closing  to  preserve  their  status  as  qualifying
     facilities.  Despite the issuance of the call notice,  Generation continues
     to pursue options to sell its investment in Sithe in its entirety.

               Generation  is a 50% owner of AmerGen and has  accounted  for the
     investment as an unconsolidated  equity  investment  through June 30, 2003.
     The book value of  Generation's  investment  in AmerGen was $260 million at
     June 30, 2003. For the six months ended June 30, 2003, AmerGen had revenues
     of $307 million.  Generation recorded $29 million of equity method earnings
     for AmerGen for the six months ended June 30, 2003.


                                       54
<PAGE>




     11. RELATED-PARTY TRANSACTIONS (Exelon, ComEd, PECO and Generation)

              Exelon's financial statements reflect related-party transactions
     with unconsolidated affiliates as reflected in the tables below.

<TABLE>
<CAPTION>


                                                                  Three Months Ended June 30,     Six Months Ended June 30,
                                                                  ---------------------------     -------------------------
                                                                            2003         2002         2003         2002
-----------------------------------------------------------------------------------------------------------------------
<S>                               <C>                                  <C>          <C>          <C>           <C>
     Purchased power from AmerGen (1)                                  $     110    $      60    $     177     $    116
     Interest income from AmerGen (2)                                         --           --            1            1
     Interest expense to Sithe (3)                                             3           --            6           --
     Services provided to AmerGen (4)                                         18           16           35           30
     Services provided to Sithe (5)                                           --           --            1           --
     Services provided by Sithe (6,7)                                          2           --            5            1
-----------------------------------------------------------------------------------------------------------------------

                                                                                    June 30, 2003     December 31, 2002
-----------------------------------------------------------------------------------------------------------------------
     Net receivable from AmerGen (1,2,4)                                            $          --              $     39
     Net payable to AmerGen (1,2,4)                                                            17                    --
     Net payable to Sithe (5,6,7)                                                               5                     7
     Note payable to Sithe (3)                                                                326                   534
-----------------------------------------------------------------------------------------------------------------------

</TABLE>

(1)      Generation has entered into PPAs dated June 26, 2003, December 18,
         2001, and November 22, 1999 with AmerGen.
         Generation has agreed to purchase 100% of the energy generated by
         Oyster Creek through April 9, 2009. Generation has agreed to purchase
         all the energy from Unit No. 1 at Three Mile Island Nuclear Station
         from January 1, 2002 through December 31, 2014. Generation has agreed
         to purchase all of the residual energy from Clinton through December
         31, 2004. Currently, the residual output is approximately 31% of the
         total output of Clinton.
(2)      In February 2002, Generation entered into an agreement to loan AmerGen
         up to $75 million at an interest rate equal to the one-month London
         Interbank Offering Rate plus 2.25%. In July 2002, the limit of the loan
         agreement was increased to $100 million and the maturity date was
         extended to July 1, 2003. As of June 30, 2003, the principal balance of
         the loan was paid in full.
(3)      Under the terms of the agreement to acquire Exelon New England dated
         November 1, 2002, Generation issued a $534 million note to be paid in
         full on June 18, 2003 to Sithe. In June 2003, the principal of the note
         was increased $2 million and the payment terms of the note were
         changed. Generation paid $210 million of principal in June 2003 and the
         balance of the note is to be paid by December 1, 2003 or upon change of
         control. The note bears interest at the rate equal to LIBOR plus
         0.875%. Interest accrued on the note as of June 30, 2003 was $0.3
         million.
(4)      Under a service agreement dated March 1, 1999, Generation provides
         AmerGen with certain operation and support services to the nuclear
         facilities owned by AmerGen. This service agreement has an indefinite
         term and may be terminated by Generation or AmerGen with 90 days
         notice. Generation is compensated for these services at cost. Exelon
         also provides AmerGen with certain payroll processing services.
(5)      Under a service agreement dated December 18, 2000, Generation provides
         certain engineering and environmental services for fossil facilities
         owned by Sithe and for certain developmental projects. Generation is
         compensated for these services at cost.
(6)      Under a service agreement dated December 18, 2000, Sithe provides
         Generation certain fuel and project development services. Sithe is
         compensated for these services at cost.
(7)      Under a service agreement dated November 1, 2002, Sithe provides
         Generation certain transition services related to the transition of the
         New England acquisition that occurred on November 1, 2002.


                                       55
<PAGE>




     ComEd
              ComEd's financial statements reflect related-party transactions as
     reflected in the tables below.

<TABLE>
<CAPTION>

                                             Three Months Ended June 30,     Six Months Ended June 30,
                                             --------------------------      ------------------------
                                                 2003            2002         2003         2002
---------------------------------------------------------------------------------------------------------
 Operating revenues from affiliates
<S>           <C>                               <C>           <C>           <C>           <C>
   Generation (1)                               $   15        $   10        $   26        $   19
   Enterprises (1)                                   1             2             3             4
 Purchased power from affiliate
   Generation (2)                                  528           547         1,099         1,079
 Operating & maintenance from affiliates
   BSC (3)                                          25            26            52            65
   Enterprises (4,5)                                 3             3             6             6
 Interest income from affiliates
   UII (6)                                           6             7            12            15
   Generation (11)                                   1            --             1            --
   Other                                            --             1            --             1
 Capitalized costs
   BSC (3)                                           1             2             2             3
   Enterprises (5)                                   6             6            12            13
 Cash dividends paid to parent                      91           117           211           235
---------------------------------------------------------------------------------------------------------


                                                               June 30, 2003  December 31, 2002
---------------------------------------------------------------------------------------------------------
Receivables from affiliates (current)
  UII (6)                                                         $   12        $   15
  Generation (11)                                                    165            --
Receivables from affiliates (noncurrent)
  UII (6)                                                          1,284         1,284
  Generation (9)                                                   1,094            --
  Other                                                               19            16
Payables to affiliates (current)
  Generation decommissioning (8)                                      11            59
  Generation (1, 2, 7)                                               185           339
  BSC (3, 7)                                                          11            18
  Other                                                                2            --
Payables to affiliates (noncurrent)
  Generation decommissioning obligation (8)                           19           218
  Other                                                                7             6
Shareholders' equity - receivable from parent (10)                   554           615
---------------------------------------------------------------------------------------------------------

</TABLE>

     (1)   ComEd provides electric, transmission, and other ancillary services
           to Generation and Enterprises.
     (2)   Effective January 1, 2001, ComEd entered into a PPA with Generation.
           See Note 8 - Commitments and Contingencies for further information
           regarding the PPA. The Generation payable primarily consists of
           services related to the PPA.
     (3)   ComEd receives a variety of corporate support services from Exelon
           Business Services Company (BSC), including legal, human resource,
           financial, information technology, supply management and corporate
           governance services. A portion of such services, provided at cost
           including applicable overhead, is capitalized.
     (4)   ComEd has contracted with Exelon Services to provide energy
           conservation services to ComEd customers.
     (5)   ComEd receives substation and transmission engineering and
           construction services under contracts with InfraSource. A portion of
           such services is capitalized.
     (6)   ComEd has a note and interest receivable with a variable interest
           rate of the one month forward LIBOR rate plus 50 basis points from
           Unicom Investments Inc. (UII) relating to the December 1999 fossil
           plant sale. This note matures in December 2011.



                                       56
<PAGE>

     (7)   In order to benefit from economies of scale, ComEd processes certain
           invoice payments on behalf of Generation and BSC.
     (8)   ComEd has a short-term and long-term payable to Generation, primarily
           representing ComEd's legal requirements to remit collections of
           nuclear decommissioning costs from customers to Generation.
     (9)   ComEd has a receivable from Generation, related to a regulatory
           liability as a result of the adoption of SFAS No. 143. For further
           information see Note 2 - New Accounting Principles and Accounting
           Changes.
    (10)   ComEd has a non-interest bearing receivable from Exelon related to
           Exelon's agreement to fund future income tax payments resulting from
           the collection by ComEd of instrument funding changes. The receivable
           is expected to be settled over the years 2003 through 2008.
    (11)   ComEd participates in Exelon's intercompany money pool. ComEd had
           various notes to and earned interest from Generation under the money
           pool.

     PECO
              PECO's financial statements reflect a number of related-party
     transactions as reflected in the table below.

<TABLE>
<CAPTION>


                                           Three Months Ended June 30,      Six Months Ended June 30,
                                           ---------------------------      -------------------------
                                                  2003         2002         2003         2002
--------------------------------------------------------------------------------------------------------
Operating revenues from affiliate
<S>          <C>                                 <C>           <C>           <C>           <C>
  Generation (1)                                 $  3          $  3          $  5          $  7
Purchased power from affiliate
  Generation (2)                                  324           346           681           649
Operating & maintenance from affiliates
  BSC (3)                                          10             9            22            26
  Enterprises (4)                                   1             8             3            16
Capitalized costs
  BSC (3)                                           2             5             5             6
  Enterprises (4)                                   7           --             13            10
Cash dividends paid to parent                      76            85           165           170
--------------------------------------------------------------------------------------------------------



                                                      June 30, 2003    December 31, 2002
--------------------------------------------------------------------------------------------------------
Payables to affiliates (current)
  Generation (2)                                           $  121          $  124
  BSC (3)                                                      12              26
  Enterprises (4)                                               3              19
  Other                                                         1               1
Payable to affiliate (noncurrent)
  Generation (5)                                               16            --
Shareholders' equity - receivable from parent (6)           1,698           1,758
--------------------------------------------------------------------------------------------------------
</TABLE>


     (1) PECO provides energy to Generation for Generation's own use.
     (2) Effective January 1, 2001, PECO entered into a PPA with Generation. See
         Note 8 - Commitments and Contingencies for further information
         regarding the PPA.
     (3) PECO provides services to BSC related to invoice processing. PECO
         receives a variety of corporate support services from BSC, including
         legal, human resource, financial, information technology, supply
         management and corporate governance services. Such services are
         provided at cost, including applicable overhead. Some of these costs
         are capitalized.
     (4) PECO receives services from Enterprises for construction, which are
         capitalized, and the deployment of automated meter reading technology,
         which are expensed.
     (5) PECO has a payable to Generation related to a regulatory asset as a
         result of the adoption of SFAS No. 143. See Note 2 - New Accounting
         Principles and Accounting Changes for further discussion of the
         adoption of SFAS No. 143.
     (6) PECO has a non-interest bearing receivable from Exelon related to
         Exelon's agreement to fund future income tax payments resulting from
         the collection of PECO's stranded costs recovery. The receivable is
         expected to be settled over the years 2003 through 2010.


                                       57
<PAGE>



     Generation
              Generation's financial statements reflect related-party
     transactions with unconsolidated affiliates as reflected in the tables
     below.
<TABLE>
<CAPTION>

                                                                  Three Months Ended June 30,   Six Months Ended June 30,
                                                                  ---------------------------   -------------------------
                                                                            2003         2002         2003         2002
-----------------------------------------------------------------------------------------------------------------------
<S>                               <C>                                  <C>          <C>          <C>             <C>
     Purchased power from AmerGen (1)                                  $     110    $      60    $     177       $  116
     Interest income from AmerGen (2)                                         --           --            1            1
     Interest expense to Sithe (3)                                             3           --            6           --
     Services provided to AmerGen (4)                                         18           16           35           30
     Services provided to Sithe (5)                                           --           --            1           --
     Services provided by Sithe (6,7)                                          2           --            5            1
----------------------------------------------------------------------------------------------------------------------

                                                                                    June 30, 2003     December 31, 2002
----------------------------------------------------------------------------------------------------------------------
     Net receivable from AmerGen (1,2,4)                                            $          --                $   39
     Net payable to AmerGen (1,2,4)                                                            19                    --
     Net payable to Sithe (5,6,7)                                                               5                     7
     Note payable to Sithe (3)                                                                326                   534
----------------------------------------------------------------------------------------------------------------------

</TABLE>


     (1) Generation has entered into PPAs dated June 26, 2003, December 18,
         2001, and November 22, 1999 with AmerGen. Generation has agreed to
         purchase 100% of the energy generated by Oyster Creek through April 9,
         2009. Generation has agreed to purchase all the energy from Unit No. 1
         at Three Mile Island Nuclear Station from January 1, 2002 through
         December 31, 2014. Generation agreed to purchase all of the residual
         energy from Clinton not sold to Illinois Power through December 31,
         2004. Currently, the residual output is approximately 31% of the total
         output of Clinton, but will increase to 100% and the obligation will
         continue until the Clinton NRC license expires in 2026.
     (2) In February 2002, Generation entered into an agreement to loan AmerGen
         up to $75 million at an interest rate equal to the one-month London
         Interbank Offering Rate plus 2.25%. In July 2002, the limit of the loan
         agreement was increased to $100 million and the maturity date was
         extended to July 1, 2003. As of June 30, 2003, the principal balance of
         the loan was paid in full. Total interest earned on the loan was less
         than $1 million during the three and six months ended June 30, 2003 and
         2002.
    (3)  Under the terms of the agreement to acquire Exelon New England dated
         November 1, 2002, Generation issued a $534 million note to be paid in
         full on June 18, 2003 to Sithe. In June 2003, the principal of the note
         was increased $2 million and the payment terms of the note were
         changed. Generation paid $210 million of principal in June 2003 and the
         balance of the note is to be paid by December 1, 2003 or upon change of
         control. The note bears interest at the rate equal to LIBOR plus
         0.875%. Interest accrued on the note as of June 30, 2003 was $0.3
         million.
    (4)  Under a service agreement dated March 1, 1999, Generation provides
         AmerGen with certain operation and support services to the nuclear
         facilities owned by AmerGen. This service agreement has an indefinite
         term and may be terminated by Generation or AmerGen with 90 days
         notice. Generation is compensated for these services at cost.
    (5)  Under a service agreement dated December 18, 2000, Generation provides
         certain engineering and environmental services for fossil facilities
         owned by Sithe and for certain developmental projects. Generation is
         compensated for these services at cost. Total revenue earned under this
         service agreement was less than $1 million for the three and six months
         ended June 30, 2003 and 2002.
    (6)  Under a service agreement dated December 18, 2000, Sithe provides
         Generation certain fuel and project development services. Sithe is
         compensated for these services at cost.
    (7)  Under a service agreement dated November 1, 2002, Sithe provides
         Generation certain transition services related to the transition of the
           Exelon New England asset acquisition which occurred November 1, 2002.


                                       58
<PAGE>



              In addition to the transactions with unconsolidated affiliates
     described above, Generation's financial statements reflect a number of
     related-party transactions as reflected in the tables below.
<TABLE>
<CAPTION>


                                                       Three Months Ended June 30,             Six Months Ended June 30,
                                                       --------------------------              -------------------------
                                                           2003            2002                2003              2002
-------------------------------------------------------------------------------------------------------------------------
     Operating revenues from affiliates
<S>          <C>                                          <C>            <C>                 <C>              <C>
       ComEd (1)                                          $   528        $    547            $  1,099         $   1,079
       PECO (1)                                               324             346                 681               649
       Exelon Energy Company (2)                               44              60                 109               117
     Purchased power from affiliates
       ComEd (4)                                               13               8                  20                14
       PECO (4)                                                --               3                  --                 5
       Exelon Energy Company (4)                                2              --                   9                 2
     Operating & maintenance from affiliates
       ComEd (4)                                                2               2                   6                 5
       PECO (4)                                                 3              --                   5                 2
       BSC (6)                                                 35              35                  71                87
     Interest expense - affiliate
       ComEd (8)                                                1              --                   1                --
       Exelon (3)                                              --               1                   1                 1
     Cash distribution paid to member                          45              --                  45                --
-------------------------------------------------------------------------------------------------------------------------

                                                                                       June 30, 2003     December 31, 2002
-------------------------------------------------------------------------------------------------------------------------
     Receivables from affiliates (current)
       ComEd  (1)                                                                     $       185                 $ 339
       ComEd decommissioning receivable (7)                                                    11                    59
       PECO (1)                                                                               121                   124
       BSC (6)                                                                                 --                    14
       Exelon Energy Company (2)                                                               16                    19
       Other                                                                                    1                    --
     Receivables from affiliates (noncurrent)
       ComEd decommissioning receivable (7)                                                    19                   218
       PECO decommissioning receivable (5)                                                     16                    --
       Other                                                                                   --                     2
     Payables to affiliates (current)
       Exelon (3)                                                                               3                     3
       BSC (6)                                                                                 18                    --
     Payable to affiliate (noncurrent)
       ComEd decommissioning (5)                                                            1,094                    --
     Notes payable to affiliate - Exelon (3)                                                  226                   329
     Notes payable to affiliates - ComEd (8)                                                  165                    --
-----------------------------------------------------------------------------------------------------------------------
<FN>
(1)  Effective  January 1,  2001,  Generation  entered  into PPAs with ComEd and
     PECO. See Note 8 - Commitments and Contingencies for further information on
     the PPAs.
(2)  Generation sells power to Exelon Energy Company (an Enterprises company).
(3)  Generation has a payable to Exelon related to certain compensation plans.
(4)  Generation  purchases power from PECO for  Generation's  own use, buys back
     excess power from Exelon  Energy  Company and  purchases  transmission  and
     ancillary services from ComEd and PECO.
(5)  Generation has a long-term payable to ComEd and a long-term receivable from
     PECO  as a  result  of the  adoption  of SFAS  No.  143.  See  Note 2 - New
     Accounting  Principles and Accounting Changes for further discussion of the
     adoption of SFAS No. 143.
(6)  Generation  receives  a variety of  corporate  support  services  from BSC,
     including legal, human resource, financial,  information technology, supply
     management and corporate governance services. Such services are provided at
     cost, including applicable  overhead.  Some third-party  reimbursements due
     Generation are recovered through BSC.


                                       59
<PAGE>

(7)  Generation  has a  short-term  and had a long-term  receivable  from ComEd,
     primarily  representing  ComEd's legal requirements to remit collections of
     nuclear  decommissioning  costs from customers to Generation resulting from
     the 2001 corporate restructuring.
(8)  Generation has a note payable to ComEd related to  Generation's  short-term
     liquidity requirements.
</FN>
</TABLE>


     12. SUPPLEMENTAL FINANCIAL INFORMATION (Exelon, ComEd and PECO)

<TABLE>
<CAPTION>
                                                                                             June 30,      December 31,
     ComEd                                                                                       2003              2002
-----------------------------------------------------------------------------------------------------------------------
<S>                                                                                        <C>                    <C>
     Regulatory Assets (Liabilities)
     Nuclear decommissioning
       (see Note 2 - New Accounting Principles and Accounting Changes)                      $  (1,094)             $ --
     Nuclear decommissioning costs for retired plants                                              --               248
     Recoverable transition costs                                                                 153               175
     Reacquired debt costs and interest rate swap settlements                                     173                84
     Recoverable deferred income taxes                                                            (64)              (68)
     Other                                                                                         22                 8
-----------------------------------------------------------------------------------------------------------------------
     Total                                                                                  $    (810)          $   447
=======================================================================================================================


                                                                                             June 30,      December 31,
     PECO                                                                                        2003              2002
-----------------------------------------------------------------------------------------------------------------------
     Regulatory Assets
     Competitive transition charge                                                          $   4,478           $ 4,639
     Recoverable deferred income taxes                                                            744               729
     Non-pension postretirement benefits                                                           62                64
     Reacquired debt costs                                                                         51                53
     Nuclear decommissioning and decontamination funds                                             29                32
     Nuclear decommissioning
       (see Note 2 - New Accounting Principles and Accounting Changes)                             16                --
     MGP regulatory asset (see Note 8 - Commitments and Contingencies)                             16                20
     Compensated absences                                                                          15                 6
     Post-employment benefits                                                                       3                 3
-----------------------------------------------------------------------------------------------------------------------
     Long-term regulatory assets                                                                5,414             5,546
     Deferred energy costs (current asset)                                                         55                31
-----------------------------------------------------------------------------------------------------------------------
     Total                                                                                  $   5,469         $   5,577
=======================================================================================================================
</TABLE>

     Exelon's long-term regulatory assets and liabilities as of June 30, 2003
were $5,414 million and $810 million, respectively. Exelon's long-term
regulatory assets as of December 31, 2002 were $5,993 million.

                                       60
<PAGE>


ITEM 2. MANAGEMENT'S  DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS

(Dollars in millions, unless otherwise noted)

EXELON CORPORATION
------------------

GENERAL

     Exelon Corporation  (Exelon),  a registered public utility holding company,
through its subsidiaries, operates in three business segments:

     o    Energy  Delivery,  whose  businesses  include  the  regulated  sale of
          electricity and distribution and transmission services by Commonwealth
          Edison  Company  (ComEd) in northern  Illinois and PECO Energy Company
          (PECO) in  southeastern  Pennsylvania  and the sale of natural gas and
          distribution services by PECO in the Pennsylvania counties surrounding
          the City of Philadelphia.
     o    Generation,   consisting   of   Exelon   Generation   Company,   LLC's
          (Generation) owned and contracted for electric generating  facilities,
          energy marketing  operations,  and equity interests in Sithe Energies,
          Inc. (Sithe) and AmerGen Energy Company, LLC (AmerGen).
     o    Enterprises,   consisting  of  Exelon   Enterprises   Company,   LLC's
          (Enterprises)    competitive   retail   energy   sales,   energy   and
          infrastructure   services,   communications   and  other   investments
          (primarily  weighted  towards the energy  services and retail services
          industries).

     See  Note 6 of the  Condensed  Combined  Notes  to  Consolidated  Financial
Statements for further segment information.

RESULTS OF OPERATIONS

Three Months Ended June 30, 2003 Compared To Three Months Ended June 30, 2002

Net Income and Earnings Per Share

     Exelon's net income for the three months ended June 30, 2003 decreased $113
million or 23%, compared to the same period in 2002. Diluted earnings per common
share on the same basis  decreased  $0.36 per share, or 24%. The decrease in net
income was due to unfavorable  weather  impacts at Energy Delivery due to cooler
spring weather and a goodwill  impairment  charge  recorded at the  InfraSource,
Inc.  reporting unit within  Enterprises during the second quarter 2003. Also, a
gain was recorded in the second quarter of 2002 due to the sale of an investment
in AT&T Wireless held by Enterprises.  These decreases were partially  offset by
increased  market  sales and  mark-to-market  activity  at  Generation,  reduced
depreciation  expense resulting from lower depreciation rates at Energy Delivery
and  decreased  interest  expense  at  Energy  Delivery  due to  refinancing  of
outstanding debt at lower interest rates.



                                       61
<PAGE>


Results of Operations by Business Segment

     Exelon   evaluates  its  performance  on  a  business  segment  basis.  The
comparisons  presented under this heading are  comparisons of operating  results
and other  statistical  information  for the three months ended June 30, 2003 to
operating results and other statistical information for the same period in 2002.
These  results  reflect  intercompany  transactions,  which  are  eliminated  in
Exelon's consolidated financial statements.

     Exelon  corporate  operations  provide the  business  segments a variety of
support  services  including  legal,  human  resources,  financial,  information
technology, supply management and corporate governance services. These costs are
allocated  to the  business  segments.  Additionally,  the  results of  Exelon's
corporate  operations include costs for strategic  long-term  planning,  certain
governmental  affairs, and interest costs and income from various investment and
financing activities.

Net Income (Loss) by Business Segment

<TABLE>
<CAPTION>
                                                         Three Months Ended June 30,
                                                         ---------------------------
                                                              2003              2002         Variance          % Change
------------------------------------------------------------------------------------------------------------------------
<S>                                                       <C>              <C>                <C>                <C>
     Energy Delivery                                      $    291         $     322          $   (31)           (9.6%)
     Generation                                                142                84               58            69.0%
     Enterprises                                               (61)               83             (144)         (173.5%)
     Corporate                                                  --                (4)               4          (100.0%)
------------------------------------------------------------------------------------------------------
     Total                                                $    372         $     485          $  (113)          (23.3%)
======================================================================================================
</TABLE>

Results of Operations - Energy Delivery


<TABLE>
<CAPTION>
                                                                  Three Months Ended June 30,
                                                                 ---------------------------
      Energy Delivery                                                       2003         2002     Variance     % Change
------------------------------------------------------------------------------------------------------------------------
<S>                                                                    <C>          <C>            <C>            <C>
     Operating revenues                                                $   2,322    $   2,476      $  (154)       (6.2%)
     Revenue, net of purchased power & fuel expense                        1,336        1,465         (129)       (8.8%)
     Operating income                                                        666          736          (70)       (9.5%)
     Income before income taxes                                              481          522          (41)       (7.9%)
     Net income                                                              291          322          (31)       (9.6%)
-------------------------------------------------------------------------------------------------------------------------
</TABLE>

     The changes in Energy Delivery's  revenue,  net of purchased power and fuel
expense, for the three months ended June 30, 2003 compared to the same period in
2002, included the following:

     o    unfavorable  weather  impacts of $66 million,  primarily the result of
          cooler spring weather,
     o    unfavorable  pricing  changes of $22 million  related to ComEd's Power
          Purchase Agreement (PPA) with Generation,
     o    net  unfavorable  changes  due to  customer  choice  of  $20  million,
          including   ComEd's   customers   electing  to  purchase  energy  from
          alternative energy suppliers or electing ComEd's Power Purchase Option
          (PPO), under which  non-residential  customers can purchase power from
          ComEd  at  a  market-based  rate,  and  customers  in  PECO's  service
          territory selecting an alternative electric generation supplier,
     o    unfavorable   variance  of  $16  million  under  the  ComEd  PPA  with
          Generation related to decommissioning  collections associated with the
          adoption of SFAS No. 143 in 2003,



<PAGE>

          which were not recorded in purchased  power in 2002 (see Note 2 of the
          Condensed Combined Notes to Consolidated Financial Statements),
     o    changes in  customer  rates  resulting  in an $8  million  unfavorable
          variance, and
     o    lower PJM ancillary  charges  resulting in a favorable  variance of $7
          million.

     The  changes in  operating  income,  other than  changes in revenue  net of
purchased  power and fuel  expense,  for the three  months  ended June 30,  2003
compared to the same period in 2002, included the following:

     o    reduction in depreciation  expense of $24 million due to the impact of
          lower  depreciation  rates at ComEd effective July 1, 2002,  partially
          offset by increased depreciation expense in 2003 of $11 million due to
          higher plant in service balances,
     o    reduction  of   amortization   expense  of  $16  million  for  nuclear
          decommissioning of retired plants at ComEd due to the adoption of SFAS
          No. 143 (see Note 2 of the Condensed  Combined  Notes to  Consolidated
          Financial  Statements),
     o    decreased   costs  of  $7   million   associated   with  the   initial
          implementation of automated meter reading services at PECO, and
     o    a reversal of $12 million of accrued use tax at PECO as a result of an
          audit settlement.

     The changes in income  before  income taxes for the three months ended June
30, 2003  compared  to the same period in 2002 included a reduction in interest
expense  primarily  related to a decrease  of $24 million  attributable  to less
outstanding debt and refinancing of existing debt at lower interest rates.

     Energy Delivery's  effective income tax rate was 39.5% for the three months
ended June 30, 2003, compared to 38.3% for the same period in 2002.





                                       63
<PAGE>

<TABLE>
<CAPTION>
                Energy Delivery  Operating  Statistics and Revenue Detail
         Energy Delivery's electric sales statistics and revenue detail are as follows:


                                                               Three Months Ended June 30,
                                                               ---------------------------
Retail Deliveries - (in gigawatthours (GWhs))(1)                       2003         2002     Variance     % Change
-------------------------------------------------------------------------------------------------------------------
<S>                                                                 <C>          <C>           <C>        <C>
Bundled Deliveries (2)
Residential                                                           7,437        7,977         (540)      (6.8%)
Small Commercial & Industrial                                         6,646        7,481         (835)     (11.2%)
Large Commercial & Industrial                                         5,378        6,049         (671)     (11.1%)
Public Authorities & Electric Railroads                               1,555        1,885         (330)     (17.5%)
-------------------------------------------------------------------------------------------------------
   Total Bundled Deliveries                                          21,016       23,392       (2,376)     (10.2%)
-------------------------------------------------------------------------------------------------------
Unbundled Deliveries (3)
Alternative Energy Suppliers
----------------------------
Residential                                                             186          557         (371)     (66.6%)
Small Commercial & Industrial                                         1,580        1,179          401       34.0%
Large Commercial & Industrial                                         2,320        1,635          685       41.9%
Public Authorities & Electric Railroads                                 247          181           66       36.5%
-------------------------------------------------------------------------------------------------------
                                                                      4,333        3,552          781       22.0%
-------------------------------------------------------------------------------------------------------
PPO (ComEd Only)
----------------
Small Commercial & Industrial                                           869          839           30        3.6%
Large Commercial & Industrial                                         1,318        1,392          (74)      (5.3%)
Public Authorities & Electric Railroads                                 531          274          257       93.8%
-------------------------------------------------------------------------------------------------------
                                                                      2,718        2,505          213        8.5%
-------------------------------------------------------------------------------------------------------
   Total Unbundled Deliveries                                         7,051        6,057          994       16.4%
-------------------------------------------------------------------------------------------------------
Total Retail Deliveries                                              28,067       29,449       (1,382)      (4.7%)
=======================================================================================================
<FN>
(1)  One GWh is the equivalent of one million kilowatthours (kWh).
(2)  Bundled service reflects deliveries to customers taking electric generation
     service under tariffed rates.
(3)  Unbundled   service  reflects   customers   electing  to  receive  electric
     generation service from an alternative energy supplier or ComEd's PPO.

</FN>
</TABLE>





                                       64
<PAGE>

<TABLE>
<CAPTION>
                                                            Three Months Ended June 30,
                                                            ---------------------------
Electric Revenue                                                       2003         2002     Variance     % Change
------------------------------------------------------------------------------------------------------------------
<S>                                                               <C>          <C>          <C>             <C>
Bundled Revenues (1)
Residential                                                       $     769    $     801    $     (32)      (4.0%)
Small Commercial & Industrial                                           585          669          (84)     (12.6%)
Large Commercial & Industrial                                           351          404          (53)     (13.1%)
Public Authorities & Electric Railroads                                 102          121          (19)     (15.7%)
-------------------------------------------------------------------------------------------------------
   Total Bundled Revenues                                             1,807        1,995         (188)      (9.4%)
-------------------------------------------------------------------------------------------------------
Unbundled Revenues (2)
Alternative Energy Suppliers
----------------------------
Residential                                                              14           42          (28)     (66.7%)
Small Commercial & Industrial                                            49           30           19       63.3%
Large Commercial & Industrial                                            48           33           15       45.5%
Public Authorities & Electric Railroads                                   8            5            3        60.0%
-------------------------------------------------------------------------------------------------------
                                                                        119          110            9        8.2%
-------------------------------------------------------------------------------------------------------
PPO (ComEd Only)
----------------
Small Commercial & Industrial                                            59           55            4        7.3%
Large Commercial & Industrial                                            72           76           (4)      (5.3%)
Public Authorities & Electric Railroads                                  28           17           11       64.7%
-------------------------------------------------------------------------------------------------------
                                                                        159          148           11        7.4%
-------------------------------------------------------------------------------------------------------
   Total Unbundled Revenues                                             278          258           20        7.8%
-------------------------------------------------------------------------------------------------------
Total Electric Retail Revenues                                        2,085        2,253         (168)      (7.5%)
-------------------------------------------------------------------------------------------------------
   Wholesale and Miscellaneous Revenue (3)                              127          139          (12)      (8.6%)
-------------------------------------------------------------------------------------------------------
Total Electric Revenue                                            $   2,212    $   2,392     $   (180)      (7.5%)
=======================================================================================================
<FN>

(1)  Bundled revenue  reflects  deliveries to customers  taking electric service
     under  tariffed  rates,  which  include the cost of energy and the delivery
     cost  of the  transmission  and  the  distribution  of the  energy.  PECO's
     tariffed rates also include a competitive transition charge (CTC).
(2)  Unbundled  revenue  reflects  revenue  from  customers  electing to receive
     electric  generation service from an alternative energy supplier or ComEd's
     PPO.  Revenue  from  customers  choosing  an  alternative  energy  supplier
     includes a distribution  charge and a CTC. Revenue  from customers choosing
     ComEd's PPO includes an energy  charge at market  rates,  transmission  and
     distribution  charges  and  a  CTC.   Transmission  charges  received  from
     alternative  energy  suppliers are included in wholesale and  miscellaneous
     revenue.
(3)  Wholesale and miscellaneous revenues include transmission revenue, sales to
     municipalities and other wholesale energy sales.

</FN>
</TABLE>

     The differences in electric retail revenues for the three months ended June
30,  2003 as  compared  to the same  period  in 2002  were  attributable  to the
following:

                                                              Variance
-------------------------------------------------------------------------
     Weather                                                   $  (129)
     Customer choice                                               (46)
     Volume                                                         18
     Rate changes                                                   (8)
     Other effects                                                  (3)
-------------------------------------------------------------------------
     Electric retail revenue                                   $  (168)
=========================================================================

o    Weather. The demand for electricity is impacted by weather conditions. Very
     warm  weather in summer  months and very cold  weather in other  months are
     referred  to as  "favorable  weather  conditions"   because  these  weather
     conditions  result in  increased  sales of  electricity.  Conversely,  mild
     weather reduces demand.  The weather impact for the three months ended June
     30, 2003 was unfavorable compared to the same period in 2002 as a result of
     cooler spring  weather in 2003.  Cooling  degree-days in the ComEd and PECO
     service territories




                                       65
<PAGE>

     were 63% lower and 40% lower,  respectively,  in 2003 as  compared to 2002.
     Heating degree-days in the ComEd and PECO service territories were 1% lower
     and 38% higher, respectively, in 2003 as compared to 2002.
o    Customer  Choice.  All ComEd and PECO customers have the choice to purchase
     energy from alternative  suppliers.  This affects revenues from the sale of
     energy but not revenue  from the  delivery of  electricity  since ComEd and
     PECO continue to deliver  electricity  that is purchased  from  alternative
     suppliers.  For the  three  months  ended  June  30,  2003,  15% of  energy
     delivered  to Energy  Delivery's  customers  was  provided  by  alternative
     electric  suppliers.  The decrease in electric retail  revenues  includes a
     decrease in revenues of $38 million from customers in Illinois  electing to
     purchase  energy from an ARES or ComEd's PPO, and a decrease in revenues of
     $8 million from customers in Pennsylvania selecting an alternative electric
     generation supplier. During the second quarter of 2003, approximately 2,500
     customers  temporarily  returned  to ComEd's  PPO as a result of an ARES no
     longer providing service in Illinois.

     The Pennsylvania  Utility  Commission's (PUC) Final Electric  Restructuring
Order established market share thresholds (MST) to promote competition.  The MST
requirements  provide  that  if,  as of  January  1,  2003,  less  than  50%  of
residential  and  commercial  customers  have  chosen  an  alternative  electric
generation supplier, the number of customers sufficient to meet the MST shall be
randomly selected and assigned to an alternative  electric  generation  supplier
through a PUC  determined  process.  On January 1, 2003, the number of customers
choosing an alternative  electric  generation  supplier did not meet the MST. In
January  2003,  PECO  submitted to the PUC an MST plan to meet the 50% threshold
requirement  for its  commercial  customers,  which was  approved  by the PUC in
February  2003.  As of March 31,  2003,  an auction had been  completed  for the
commercial  customers.  In May 2003, the customer enrollment phase was completed
and customers that did not choose to opt out of the program were  transferred to
the alternative  electric generation  suppliers.  In February 2003, PECO filed a
residential  customer MST plan,  and on May 1, 2003,  the PUC approved the plan.
The approved plan provides for a two-step  process with a total of up to 400,000
residential  customers being assigned to winning alternative electric generation
supplier  bidders:  up to 100,000 in July 2003, and another  300,000 in December
2003.  The auction for the first phase of the  residential  program  received no
supplier bids. Therefore,  according to the MST plan requirements,  75% of those
customers  are  required to be added to the auction for the second  phase of the
residential program for a total of 375,000 customers. The auction for the second
phase of the  residential  customer MST plan is scheduled for September 2003 and
the  selected  customers  would be  transferred  effective  December  2003.  Any
customer  transferred  would have the right to return to PECO at any time.  PECO
does not expect the  transfer  of  customers  pursuant to the MST plan to have a
material impact on its results of operations, financial position or cash flows.

o    Volume.  Revenues from higher  delivery  sales,  exclusive of the effect of
     weather,  increased  $25  million  at ComEd due to an  increased  number of
     customers  and  increased  usage per customer,  primarily  residential  and
     ComEd's  PPO.  Revenues  from  delivery  sales,  exclusive of the effect of
     weather, decreased $7 million at PECO due to lower usage in the residential
     and large commercial and industrial  customer classes,  partially offset by
     an increase in usage by small commercial and industrial customers.

o    Rate  Changes.  The  decrease  in  revenues  attributable  to rate  changes
     reflects  decreased  wholesale market prices which decreased energy revenue
     received under ComEd's PPO by




                                       66
<PAGE>

     $48 million.  This was partially offset by the collection of $40 million in
     additional  CTC's in 2003 by ComEd due to an increase in sales to customers
     choosing  an  alternative  energy  supplier  (ARES) or the ComEd PPO and an
     increase in CTC rates due to lower  wholesale  market price of electricity,
     net of increased mitigation factors.

     Energy Delivery's gas sales statistics and revenue detail were as follows:

<TABLE>
<CAPTION>
                                                                  Three Months Ended June 30,
                                                                  ---------------------------
                                                                            2003         2002     Variance     % Change
-------------------------------------------------------------------------------------------------------------------------
<S>                                                                       <C>          <C>             <C>        <C>
     Deliveries in million cubic feet (mmcf)                              15,001       14,286          715        5.0%
     Revenue                                                           $     110    $      84    $      26       31.0%
-------------------------------------------------------------------------------------------------------------------------
</TABLE>

     The  changes in gas  revenue  for the three  months  ended June 30, 2003 as
compared to the same period in 2002, were as follows:

<TABLE>
<CAPTION>
                                                                                                               Variance
------------------------------------------------------------------------------------------------------------------------
<S>                                                                                                            <C>
     Weather                                                                                                   $     14
     Rate changes                                                                                                    10
     Volume                                                                                                           2
------------------------------------------------------------------------------------------------------------------------
     Gas revenue                                                                                               $     26
========================================================================================================================
</TABLE>

o    Weather.  The demand for gas is impacted by weather  conditions.  Very cold
     weather  in  non-summer  months  is  referred  to  as  "favorable   weather
     conditions,"  because these weather conditions result in increased sales of
     gas.  Conversely,  mild  weather  reduces  demand.  The weather  impact was
     favorable  compared to the prior year as a result of cooler spring weather.
     Heating degree-days increased 38% in PECO's service territory for the three
     months ended June 30, 2003 compared to the same period in 2002.
o    Rate Changes.  The favorable  variance in rate changes is attributable to a
     15% increase and a 7% increase in the purchased  gas  adjustment by the PUC
     effective March 1, 2003, and June 1, 2003,  respectively.  The average rate
     per  million  cubic feet for the three  months  ended June 30, 2003 was 22%
     higher  than the rate in the same  period  in 2002.  PECO's  gas  rates are
     subject to periodic adjustments by the PUC and are designed to recover from
     or refund to customers the difference  between actual cost of purchased gas
     and the amount included in base rates and to recover or refund increases or
     decreases in certain state taxes not recovered in base rates.
o    Volume. Exclusive of weather impacts, delivery volume was consistent in the
     three months  ended June 30, 2003  compared to the same period in 2002 with
     increased  retail sales partially offset by lower  transportation  volumes.
     Deliveries  to  customers,  excluding  transportation  and the  effects  of
     weather,  increased 4% in the three months ended June 30, 2003  compared to
     the same period in 2002.




                                       67
<PAGE>

     Results of Operations - Generation

<TABLE>
<CAPTION>
                                                                Three Months Ended June 30,
                                                                ---------------------------
                                                                            2003         2002     Variance     % Change
------------------------------------------------------------------------------------------------------------------------
<S>                                                                    <C>          <C>              <C>          <C>
     Operating revenues                                                $   1,886    $   1,559        $ 327        21.0%
     Revenue, net of purchased power & fuel expense                          738          630          108        17.1%
     Operating income                                                        201          113           88        77.9%
     Income before income taxes                                              233          135           98        72.6%
     Net income                                                              142           84           58        69.0%
------------------------------------------------------------------------------------------------------------------------
</TABLE>

     The  changes  in  Generation's  revenue,  net of  purchased  power and fuel
expense, for the three months ended June 30, 2003 compared to the same period in
2002, included the following:

     o    increased  market  sales of $385  million  primarily  attributable  to
          regional  demand and price  increases,  partially  offset by increased
          purchased  power of $95 million  and  increased  fuel  expense of $124
          million,
     o    increases of $31 million for generation  from plants  acquired  during
          2002 resulting in higher market sales,
     o    unfavorable   weather   conditions  in  the  ComEd  and  PECO  service
          territories  in 2003  resulted  in a net  volume  decrease  offset  by
          overall price increases of $57 million,
     o    increased  revenue  from  ComEd  of $16  million  associated  with the
          adoption of SFAS No. 143, which was not included in revenue in 2002,
     o    mark-to-market  gains on  hedging  activities  of $32  million in 2003
          compared to $4 million in 2002, and
     o    additional  nuclear fuel  amortization  of $10 million  resulting from
          under performing fuel at the Quad Cities Unit 1.

     The  changes in  operating  income,  other than  changes in revenue  net of
purchased  power and fuel  expense,  for the three  months  ended June 30,  2003
compared to the same period in 2002, included the following:

     o    higher  costs of $8 million for  employee  medical,  pension and other
          employee payroll and benefit costs in 2003,
     o    increased  operating and maintenance  (O&M) costs of $8 million due to
          asset acquisitions made after the second quarter of 2002 and including
          a $5 million  impairment  charge  recorded  in 2003  related to Mystic
          Station Units 4, 5, and 6,
     o    reduced  refueling outage costs of $21 million,  including $17 million
          at one of  Generation's  co-owned  facilities,  resulting  from  fewer
          refueling outage days in 2003,
     o    additional  depreciation of $4 million due to capital additions placed
          in service  and plant  acquisitions  made after the second  quarter of
          2002 and $7  million  related  to plant  acquisitions  made  after the
          second  quarter  of 2002,  partially  offset  by $3  million  of lower
          depreciation due to life extensions of asset additions in 2002, and
     o    accretion  expense of $43  million  recognized  in 2003 to accrete the
          asset  retirement  obligation  established at the adoption of SFAS No.
          143, partially offset by the elimination of decommissioning expense of
          $31 million, also as a result of the adoption of SFAS No. 143.





                                       68
<PAGE>

     The changes in income  before  income taxes for the three months ended June
30, 2003 compared to the same period in 2002, included the following:

     o    increased  decommissioning  trust  investment  income of $15  million,
          which is almost entirely offset by accretion expense recorded in O&M,
     o    increased  equity  in  earnings  of  unconsolidated  affiliates  of $9
          million, and
     o    increased  interest  expense  of $9 million  primarily  due to reduced
          capitalized  interest in 2003 in addition to interest  incurred on the
          note payable to Sithe.

     Generation's effective income tax rate was 39.2% for the three months ended
June 30, 2003  compared to 37.7% for the same period in 2002.  This increase was
primarily   attributable  to  an  increase  in  taxes  related  to  the  nuclear
decommissioning trust funds.

     Generation Operating Statistics
     Generation's  sales and the supply of these  sales,  excluding  the trading
portfolio, were as follows:

<TABLE>
<CAPTION>
                                                                  Three Months Ended June 30,
                                                                  ---------------------------
     Sales (in GWhs)                                                        2003         2002     Variance     % Change
-----------------------------------------------------------------------------------------------------------------------
<S>                                                                       <C>          <C>          <C>          <C>
     Energy Delivery and Exelon Energy Company                            26,869       29,649       (2,780)      (9.4%)
     Market Sales                                                         27,449       20,589        6,860       33.3%
-----------------------------------------------------------------------------------------------------------
     Total Sales                                                          54,318       50,238        4,080        8.1%
===========================================================================================================

                                                                  Three Months Ended June 30,
                                                                  ---------------------------
     Supply of Sales (in GWhs)                                              2003         2002     Variance     % Change
-----------------------------------------------------------------------------------------------------------------------
     Nuclear Generation (1)                                               29,619       28,776          843        2.9%
     Purchases - non-trading portfolio (2)                                19,344       17,978        1,366        7.6%
     Fossil and Hydro Generation                                           5,355        3,484        1,871       53.7%
-----------------------------------------------------------------------------------------------------------
     Total Supply                                                         54,318       50,238        4,080        8.1%
===========================================================================================================
<FN>
     (1) Excluding AmerGen.
     (2) Including purchased power agreements with AmerGen.
</FN>
</TABLE>

     Trading volume of 7,919 GWhs and 8,566 GWhs for the three months ended June
30,  2003 and  2002,  respectively,  is not  included  in the table  above.  The
decrease  in trading  volume is a result of reduced  volumetric  and VAR trading
limits in 2003, which are set by Exelon's Risk Management Committee and approved
by the Board of Directors.





                                       69
<PAGE>

     Generation's  average margin and other  operating data for the three months
ended June 30, 2003 and 2002 were as follows:

<TABLE>
<CAPTION>
                                                                            Three Months Ended June 30,
                                                                            ---------------------------
      ($/MWh)                                                                   2003               2002        % Change
-----------------------------------------------------------------------------------------------------------------------
<S>                                                                      <C>              <C>                     <C>
     Average Revenue
         Energy Delivery and Exelon Energy Company                       $     32.67      $      32.06            1.9%
         Market Sales                                                          34.98             30.69           14.0%
         Total - excluding the trading portfolio                               33.83             31.50            7.4%

     Average Supply Cost (1) - excluding the trading portfolio           $     20.71      $      18.79           10.2%

     Average Margin - excluding the trading portfolio                    $     13.12       $     12.71            3.2%
-----------------------------------------------------------------------------------------------------------------------
<FN>
(1)      Average supply cost includes purchased power and fuel costs.
</FN>
</TABLE>


<TABLE>
<CAPTION>
                                                                                            Three Months Ended June 30,
                                                                                            ---------------------------
                                                                                                   2003            2002
------------------------------------------------------------------------------------------------------------------------
<S>                                <C>                                                             <C>             <C>
     Nuclear fleet capacity factor (1)                                                             94.0%           92.1%
     Nuclear fleet production cost per MWh (1)                                               $    12.08     $     12.54
     Average purchased power cost for wholesale operations per MWh                           $    43.15     $     39.96
------------------------------------------------------------------------------------------------------------------------
<FN>
     (1) Including AmerGen and excluding Salem.
</FN>
</TABLE>

     The  factors  below  contributed  to the overall  increase in  Generation's
average  margin for the three months ended June 30, 2003 as compared to the same
period in 2002.

     Generation's average revenue per MWh was affected by:

     o    increased  weighted  average on and off-peak prices per MWh for supply
          agreements with ComEd,
     o    higher prices per MWh on sales under supply agreements with PECO, and
     o    higher market prices.

     Generation's supply mix changed as a result of:

     o    increased  nuclear  generation  due to a lower number of refueling and
          unplanned outages during 2003 compared to 2002,
     o    increased fossil generation due to the effect of the Sithe New England
          (now known as Exelon New England)  plants  acquired in November  2002,
          which in total account for an increase of 1,498 GWhs, and
     o    increased   quantity  of  purchased  power  to  service  greater  than
          anticipated  customer  loads  outside of the Energy  Delivery  service
          areas.

     Higher nuclear capacity factors and decreased nuclear  production costs are
primarily  due to 20 fewer  planned  refueling  outage  days,  resulting in a $4
million  decrease in outage  costs,  in the three  months ended June 30, 2003 as
compared to the same period in 2002.  Additionally,  the three months ended June
30, 2003 included nine unplanned  outages  compared to eight  unplanned  outages
during the three months ended June 30, 2002.

     Generation's  financial results are greatly dependent on the performance of
its nuclear units, including Generation's ability to maintain stable cost levels
and high nuclear  capacity





                                       70
<PAGE>

factors.  Problems that may occur at nuclear facilities that result in increased
costs include  accelerated  replacement of suspect fuel  assemblies,  generation
reductions to make repairs and  mid-cycle  outages.  For example,  in the second
quarter of 2003,  the Quad  Cities Unit 1 required a  significant  repair and is
unable to operate  above an 85%  capacity  factor  until the Nuclear  Regulatory
Commission  (NRC)  inspects and approves the  maintenance  work.  Although  this
individual matter did not result in a significant  decrease in operating income,
this type of reduction in operational capacity can adversely affect Generation's
financial results.  Generation  anticipates NRC approval of the maintenance work
and to return the unit to its normal operating capacity in the near future.


Results of Operations - Enterprises

<TABLE>
<CAPTION>
                                                             Three Months Ended June 30,
                                                             ---------------------------
                                                                       2003         2002     Variance     % Change
---------------------------------------------------------------------------------------------------------------------
<S>                                                                <C>          <C>             <C>          <C>
Operating revenues                                                 $    443     $    476        $ (33)       (6.9%)
Operating loss                                                          (57)         (15)         (42)         n.m.
Income (loss) before income taxes                                       (95)         142         (237)     (166.9%)
Net income (loss)                                                       (61)          83         (144)     (173.5%)
---------------------------------------------------------------------------------------------------------------------
<FN>
n.m. - not meaningful
</FN>
</TABLE>

     The changes in Enterprises'  operating loss for the three months ended June
30, 2003 compared to the same period in 2002, included the following:

     o    an impairment charge of $47 million before income taxes related to the
          goodwill of InfraSource, Inc. The applicable assets and liabilities of
          InfraSource,  Inc. were  classified as held for sale during the second
          quarter of 2003,
     o    lower operating income at InfraSource,  Inc. of $12 million  primarily
          resulting from a decrease in the electric line of business,
     o    higher  operating  income  at  Exelon  Energy  Company  of $9  million
          resulting  from lower  operating  expense from the  discontinuance  of
          retail sales in the PJM region including  accelerated  depreciation of
          assets  of $7  million  and  general  and  administrative  costs of $2
          million in 2002,
     o    higher operating income at Exelon Thermal of $3 million resulting from
          lower production costs, and
     o    reductions in general and administrative expenses of $6 million.

     The changes in income (loss) before income taxes for the three months ended
June 30,  2003  compared  to the same  period  in 2002,  include  the  following
additional impacts:

     o    a pre-tax gain of $198 million  recorded on the AT&T  Wireless sale in
          2002,
     o    an  impairment  charge in 2003 of  energy-related  investments  of $22
          million and communications  investments of $13 million due to an other
          than temporary  decline in value  compared to an impairment  charge in
          2002 of  communications  investments  of $27 million,  energy  related
          investments  of $9 million and a net  impairment of other assets of $4
          million, and
     o    lower equity in earnings of  unconsolidated  affiliates  of $3 million
          resulting from lower earnings at a communications joint venture.




                                       71
<PAGE>

     The effective income tax rate was 35.8% for the three months ended June 30,
2003,  compared  to 41.5% for the same  period  in 2002.  This  decrease  in the
effective tax rate was  attributable to lower effective  income tax rates on the
impairments.



Six Months Ended June 30, 2003 and Six Months Ended June 30, 2002

Net Income and Earnings Per Share

     Exelon's net income for the six months ended June 30, 2003  increased  $241
million or 49%, compared to the same period in 2002. Diluted earnings per common
share on the same basis  increased  $0.72 per share,  or 47%. Net income for the
six  months  ended  June 30,  2003  reflects  $112  million  of  income  for the
cumulative  effect  of a change  in  accounting  principle  as a  result  of the
adoption of Financial  Accounting  Standards Board (FASB) Statement of Financial
Accounting (SFAS) No. 143, "Asset Retirement  Obligations" (SFAS No. 143), while
net income for the six months ended June 30, 2002 reflects a $230 million charge
for the  cumulative  effect  of a change  in  accounting  principle,  reflecting
goodwill  impairment  upon the  adoption  of SFAS No. 142,  "Goodwill  and Other
Intangible Assets" (SFAS No. 142). See Note 2 of the Condensed Combined Notes to
Consolidated   Financial  Statements  for  further  information   regarding  the
adoptions of SFAS No. 143 and SFAS No. 142.

     Income Before Cumulative Effect of Changes in Accounting Principles for the
six months ended June 30, 2003 decreased $101 million,  or 14%,  compared to the
same  period  in 2002.  Diluted  earnings  per  common  share on the same  basis
decreased  $0.33 per share,  or 15%.  The decrease in income  before  cumulative
effect  of  changes  in  accounting  principles  reflects  an  impairment  of an
investment  in Sithe  held by  Generation  in the  first  quarter  of 2003 and a
goodwill  impairment  charge recorded at the  InfraSource,  Inc.  reporting unit
within  Enterprises  during the  second  quarter  2003.  Also,  Energy  Delivery
recorded  a  one-time  charge in the first  quarter  of 2003 as the result of an
agreement (see Note 4 of the Condensed Combined Notes to Consolidated  Financial
Statements)  and a gain was  recorded  in the second  quarter of 2002 due to the
sale of an investment in AT&T  Wireless  held by  Enterprises.  These items were
partially  offset by increased  recoveries  of  competitive  transition  charges
(CTCs),  increased  market  sales and  mark-to-market  activity  at  Generation,
reduced  depreciation  expense resulting from lower depreciation rates at Energy
Delivery and decreased interest expense at Energy Delivery due to refinancing of
outstanding debt at lower interest rates.


Results of Operations by Business Segment

     The  comparisons  presented under this heading are comparisons of operating
results and other statistical information for the six months ended June 30, 2003
to operating  results and other  statistical  information for the same period in
2002. These results reflect intercompany  transactions,  which are eliminated in
Exelon's consolidated financial statements.





                                       72
<PAGE>

Net Income (Loss) Before Cumulative  Effect of Changes in Accounting  Principles
by Business Segment
<TABLE>
<CAPTION>
                                                            Six Months Ended June 30,
                                                            -------------------------
                                                              2003              2002         Variance          % Change
-------------------------------------------------------------------------------------------------------------------------
<S>                                                       <C>              <C>                <C>                <C>
     Energy Delivery                                      $    616         $     538          $    78            14.5%
     Generation                                                 89               150              (61)          (40.7%)
     Enterprises                                               (78)               55             (133)             n.m.
     Corporate                                                  (6)              (21)              15           (71.4%)
------------------------------------------------------------------------------------------------------
     Total                                                $    621         $     722          $  (101)          (14.0%)
======================================================================================================
     n.m. - not meaningful

     Net Income (Loss) by Business Segment

                                                            Six Months Ended June 30,
                                                            -------------------------
                                                              2003              2002         Variance          % Change
-------------------------------------------------------------------------------------------------------------------------
     Energy Delivery                                      $    621         $     538          $    83            15.4%
     Generation                                                197               163               34            20.9%
     Enterprises                                               (79)             (188)             109           (58.0%)
     Corporate                                                  (6)              (21)              15           (71.4%)
------------------------------------------------------------------------------------------------------
     Total                                                $    733         $     492          $   241            49.0%
======================================================================================================

     Results of Operations - Energy Delivery

                                                                     Six Months Ended June 30,
                                                                     -------------------------
      Energy Delivery                                                       2003         2002     Variance     % Change
------------------------------------------------------------------------------------------------------------------------
     Operating revenues                                                $   4,964    $   4,811      $   153         3.2%
     Revenue, net of purchased power & fuel expense                        2,789        2,777           12         0.4%
     Operating income                                                      1,360        1,296           64         4.9%
     Income before income taxes and cumulative effect of a
       change in accounting principle                                        998          864          134        15.5%
     Income before cumulative effect of a change in
       accounting principle                                                  616          538           78        14.5%
     Net income                                                              621          538           83        15.4%
------------------------------------------------------------------------------------------------------------------------
</TABLE>

     The changes in Energy Delivery's  revenue,  net of purchased power and fuel
expense,  for the six months ended June 30, 2003  compared to the same period in
2002, included the following:

     o    changes in customer rates resulting in a $75 million increase,
     o    increases in weather  normalized volumes of $34 million as a result of
          increases in the number of customers and additional  average usage per
          customer,  primarily  residential  customers  at ComEd,  and small and
          large commercial and industrial customers at PECO,
     o    net favorable weather impacts of $12 million, primarily the results of
          colder winter weather, partially offset by cooler spring weather,
     o    net  unfavorable  changes  due to  customer  choice  of  $28  million,
          including   ComEd's   customers   electing  to  purchase  energy  from
          alternative  energy  suppliers or electing  ComEd's  PPO,  under which
          non-residential   customers  can  purchase   power  from  ComEd  at  a
          market-based rate,
     o    unfavorable pricing changes of $39 million related to ComEd's PPA with
          Generation,




                                       73
<PAGE>

     o    unfavorable   variance  of  $31  million  under  the  ComEd  PPA  with
          Generation related to decommissioning  collections associated with the
          adoption of SFAS No. 143 in 2003, which were not recorded in purchased
          power  in  2002  (see  Note  2 of  the  Condensed  Combined  Notes  to
          Consolidated Financial Statements), and
     o    higher PJM ancillary charges resulted in an unfavorable variance of $8
          million.

     The  changes in  operating  income,  other than  changes in revenue  net of
purchased  power  and fuel  expense,  for the six  months  ended  June 30,  2003
compared to the same period in 2002, included the following:


     o    a net one-time charge of $41 million in 2003 at ComEd as the result of
          an  agreement  described  in Note 4 of  Condensed  Combined  Notes  to
          Consolidated Financial Statements,
     o    reduction in depreciation  expense of $48 million due to the impact of
          lower  depreciation  rates at ComEd effective July 1, 2002,  partially
          offset by increased depreciation expense in 2003 of $20 million due to
          higher plant in service balances,
     o    reduction  of   amortization   expense  of  $31  million  for  nuclear
          decommissioning of retired plants at ComEd due to the adoption of SFAS
          No. 143 (see Note 2 of the Condensed  Combined  Notes to  Consolidated
          Financial Statements),
     o    lower  amortization  of ComEd's  recoverable  transition  costs of $20
          million in 2003,
     o    a reversal of $12 million of accrued use tax at PECO as a result of an
          audit settlement, and
     o    additional  amortization  in 2003 of $15  million  at PECO  related to
          PECO's   competitive   transition   charge  in  accordance   with  the
          Pennsylvania Competitive Act.

     The changes in income before income taxes and cumulative effect of a change
in  accounting  principle for the six months ended June 30, 2003 compared to the
same period in 2002, included the following:

     o    a reduction in interest expense primarily related to a decrease of $45
          million  attributable  to less  outstanding  debt and  refinancing  of
          existing debt at lower interest rates, and
     o    the reversal in 2003 of a $12 million reserve for a potential  capital
          disallowance as the result of an agreement  described in Note 4 of the
          Condensed Combined Notes to Consolidated Financial Statements.

     Energy  Delivery's  effective  income tax rate was 38.3% for the six months
ended June 30, 2003, compared to 37.7% for the same period in 2002.

     ComEd  recorded a gain due to the  adoption of SFAS No. 143 as a cumulative
effect of a change in accounting  principle of $5 million,  net of income taxes,
in the first  quarter of 2003.  See Note 2 of the  Condensed  Combined  Notes to
Consolidated Financial Statements for further discussion of these effects.




                                       74
<PAGE>

Energy Delivery Operating Statistics and Revenue Detail

     Energy  Delivery's  electric  sales  statistics  and revenue  detail are as
follows:

<TABLE>
<CAPTION>
                                                                   Six Months Ended June 30,
                                                                   -------------------------
     Retail Deliveries - (GWhs)                                             2003         2002     Variance     % Change
------------------------------------------------------------------------------------------------------------------------
<S>                                                                       <C>          <C>             <C>        <C>
     Bundled Deliveries (1)
     Residential                                                          17,438       16,441          997        6.1%
     Small Commercial & Industrial                                        14,053       14,687         (634)      (4.3%)
     Large Commercial & Industrial                                        10,344       11,357       (1,013)      (8.9%)
     Public Authorities & Electric Railroads                               3,224        3,879         (655)     (16.9%)
-----------------------------------------------------------------------------------------------------------
        Total Bundled Deliveries                                          45,059       46,364       (1,305)      (2.8%)
-----------------------------------------------------------------------------------------------------------
     Unbundled Deliveries (2)
     Alternative Energy Suppliers
     ----------------------------
     Residential                                                             450        1,348         (898)     (66.6%)
     Small Commercial & Industrial                                         3,131        2,280          851       37.3%
     Large Commercial & Industrial                                         4,362        3,124        1,238       39.6%
     Public Authorities & Electric Railroads                                 529          319          210       65.8%
-----------------------------------------------------------------------------------------------------------
                                                                           8,472        7,071        1,401       19.8%
-----------------------------------------------------------------------------------------------------------
     PPO (ComEd Only)
     ----------------
     Small Commercial & Industrial                                         1,662        1,602           60        3.7%
     Large Commercial & Industrial                                         2,750        2,703           47        1.7%
     Public Authorities & Electric Railroads                               1,069          517          552      106.8%
-----------------------------------------------------------------------------------------------------------
                                                                           5,481        4,822          659       13.7%
-----------------------------------------------------------------------------------------------------------
        Total Unbundled Deliveries                                        13,953       11,893        2,060       17.3%
-----------------------------------------------------------------------------------------------------------
     Total Retail Deliveries                                              59,012       58,257          755        1.3%
===========================================================================================================
<FN>
     (1) Bundled  service  reflects  deliveries  to  customers  taking  electric
         generation service under tariffed rates.
     (2) Unbundled  service  reflects  customers  electing  to receive  electric
         generation service from an alternative energy supplier or ComEd's PPO.
</FN>
</TABLE>





                                       75
<PAGE>

<TABLE>
<CAPTION>
                                                                   Six Months Ended June 30,
                                                                   -------------------------
     Electric Revenue                                                       2003         2002     Variance     % Change
-------------------------------------------------------------------------------------------------------------------------
<S>                                                                    <C>          <C>           <C>             <C>
     Bundled Revenues (1)
     Residential                                                       $   1,673    $   1,563     $    110        7.0%
     Small Commercial & Industrial                                         1,177        1,249          (72)      (5.8%)
     Large Commercial & Industrial                                           692          750          (58)      (7.7%)
     Public Authorities & Electric Railroads                                 207          230          (23)     (10.0%)
------------------------------------------------------------------------------------------------------------
        Total Bundled Revenues                                             3,749        3,792          (43)      (1.1%)
------------------------------------------------------------------------------------------------------------
     Unbundled Revenues (2)
     Alternative Energy Suppliers
     ----------------------------
     Residential                                                              31           96          (65)     (67.7%)
     Small Commercial & Industrial                                            99           48           51       106.3%
     Large Commercial & Industrial                                           103           45           58       128.9%
     Public Authorities & Electric Railroads                                  17            7           10       142.9%
------------------------------------------------------------------------------------------------------------
                                                                             250          196           54       27.6%
------------------------------------------------------------------------------------------------------------
     PPO (ComEd Only)
     ----------------
     Small Commercial & Industrial                                           109           98           11       11.2%
     Large Commercial & Industrial                                           144          140            4        2.9%
     Public Authorities & Electric Railroads                                  55           29           26       89.7%
------------------------------------------------------------------------------------------------------------
                                                                             308          267           41       15.4%
------------------------------------------------------------------------------------------------------------
        Total Unbundled Revenues                                             558          463           95       20.5%
------------------------------------------------------------------------------------------------------------
     Total Electric Retail Revenues                                        4,307        4,255           52        1.2%
------------------------------------------------------------------------------------------------------------
        Wholesale and Miscellaneous Revenue (3)                              258          263           (5)      (1.9%)
------------------------------------------------------------------------------------------------------------
     Total Electric Revenue                                            $   4,565    $   4,518     $     47        1.0%
============================================================================================================
<FN>
     (1) Bundled  revenue  reflects  deliveries  to  customers  taking  electric
         service under tariffed rates,  which include the cost of energy and the
         delivery cost of the  transmission  and the distribution of the energy.
         PECO's tariffed rates also include a CTC charge.
     (2) Unbundled  revenue reflects revenue from customers  electing to receive
         electric  generation  service from an  alternative  energy  supplier or
         ComEd's PPO.  Revenue from  customers  choosing an  alternative  energy
         supplier  includes  a  distribution  charge  and a CTC.  Revenues  from
         customers  choosing  ComEd's PPO  includes  an energy  charge at market
         rates,  transmission and distribution  charges and a CTC.  Transmission
         charges  received  from  alternative  energy  suppliers are included in
         wholesale and miscellaneous revenue.
     (3) Wholesale and  miscellaneous  revenues  include  transmission  revenue,
         sales to municipalities and other wholesale energy sales.
</FN>
</TABLE>

              The  differences  in electric  retail  revenues for the six months
     ended  June  30,  2003  as  compared  to  the  same  period  in  2002  were
     attributable to the following:
<TABLE>
<CAPTION>
                                                                                                               Variance
-------------------------------------------------------------------------------------------------------------------------
<S>                                                                                                                  <C>
     Rate changes                                                                                                    75
     Volume                                                                                                          68
     Customer choice                                                                                                (66)
     Weather                                                                                                        (28)
     Other effects                                                                                                    3
-------------------------------------------------------------------------------------------------------------------------
     Electric retail revenue                                                                                   $     52
=========================================================================================================================
</TABLE>

o    Rate  Changes.  The  increase  in  revenues  attributable  to rate  changes
     reflects  the  collection  of  additional  CTC's  in 2003 by  ComEd of $146
     million due to an increase  in sales to  customers  choosing an ARES or the
     ComEd PPO and an increase in CTC rates due to lower wholesale  market price
     of electricity, net of increased mitigation factors. Lower wholesale market
     prices decreased energy revenue received under ComEd's PPO by $71 million.




                                       76
<PAGE>

o    Volume.  Revenues from higher delivery  volume,  exclusive of the effect of
     weather,  increased  due to an increased  number of customers and increased
     usage per customer,  primarily in the residential  customer class for ComEd
     and in the small and large  commercial and industrial  customer classes for
     PECO.
o    Customer  Choice.  For the six months  ended June 30,  2003,  14% of energy
     delivered  to Energy  Delivery's  customers  was  provided  by  alternative
     electric  suppliers.  The decrease in electric retail  revenues  includes a
     decrease in revenues of $77 million from customers in Illinois  electing to
     purchase  energy  from an ARES  or  ComEd's  PPO,  partially  offset  by an
     increase  in  revenues  of  $11  million  from  customers  in  Pennsylvania
     selecting or returning to PECO as their electric generation supplier.
o    Weather.  The  weather  impact for the six months  ended June 30,  2003 was
     unfavorable  compared  to the same  period  in 2002 as a result  of  cooler
     spring weather in 2003, partially offset by colder winter weather.  Cooling
     degree-days  in the ComEd and PECO service  territories  were 63% lower and
     40% lower,  respectively,  in 2003 as compared to 2002. Heating degree-days
     in the ComEd and PECO service  territories  were 13% higher and 34% higher,
     respectively, in 2003 as compared to 2002.

     Energy Delivery's gas sales statistics and revenue detail were as follows:

<TABLE>
<CAPTION>
                                                                    Six Months Ended June 30,
                                                                    -------------------------
                                                                            2003         2002     Variance     % Change
------------------------------------------------------------------------------------------------------------------------
<S>                                                                       <C>          <C>           <C>         <C>
     Deliveries in million cubic feet (mmcf)                              54,627       45,643        8,984       19.7%
     Revenue                                                           $     399    $     293    $     106       36.2%
------------------------------------------------------------------------------------------------------------------------
</TABLE>

              The changes in gas revenue for the six months  ended June 30, 2003
     as compared to the same period in 2002, were as follows:

<TABLE>
<CAPTION>
                                                                                                               Variance
------------------------------------------------------------------------------------------------------------------------
<S>                                                                                                            <C>
     Weather                                                                                                   $     73
     Volume                                                                                                          17
     Rate changes                                                                                                    13
     Other                                                                                                            3
------------------------------------------------------------------------------------------------------------------------
     Gas revenue                                                                                               $     106
========================================================================================================================
</TABLE>

o    Weather.  The weather impact was favorable  compared to the prior year as a
     result of colder  winter  weather.  Heating  degree-days  increased  34% in
     PECO's service territory for the six months ended June 30, 2003 compared to
     the same period in 2002.
o    Volume.  Exclusive of weather  impacts,  higher delivery  volume  increased
     revenue in the six months  ended June 30, 2003  compared to the same period
     in 2002  resulting from increased  retail sales  partially  offset by lower
     transportation volumes.  Deliveries to customers,  excluding transportation
     and the effects of weather,  increased  6% in the six months ended June 30,
     2003 compared to the same period in 2002.




                                       77
<PAGE>

o    Rate Changes.  The favorable  variance in rate changes is attributable to a
     15% increase and a 7% increase in the purchased  gas  adjustment by the PUC
     effective  March 1, 2003 and June 1, 2003,  respectively.  The average rate
     per  million  cubic  feet for the six months  ended  June 30,  2003 was 13%
     higher than the rate in the same 2002 period.  PECO's gas rates are subject
     to periodic  adjustments  by the PUC and are  designed  to recover  from or
     refund to customers the difference between actual cost of purchased gas and
     the amount  included  in base rates and to recover or refund  increases  or
     decreases in certain state taxes not recovered in base rates.

     Results of Operations - Generation
<TABLE>
<CAPTION>
                                                                    Six Months Ended June 30,
                                                                    -------------------------
                                                                            2003         2002     Variance     % Change
------------------------------------------------------------------------------------------------------------------------
<S>                                                                    <C>          <C>              <C>          <C>
     Operating revenues                                                $   3,765    $   3,020        $ 745        24.7%
     Revenue, net of purchased power & fuel expense                        1,417        1,264          153        12.1%
     Operating income                                                        295          202           93        46.0%
     Income before income taxes and cumulative effect
       of changes in accounting principles                                   160          246          (86)      (35.0%)
     Income before cumulative effect of changes in
       accounting principles                                                  89          150          (61)      (40.7%)
     Net income                                                              197          163           34        20.9%
------------------------------------------------------------------------------------------------------------------------
</TABLE>

     The  changes  in  Generation's  revenue,  net of  purchased  power and fuel
expense,  for the six months ended June 30, 2003  compared to the same period in
2002, included the following:

     o    increased  demand due to customers  returning to PECO from alternative
          energy suppliers and overall favorable weather conditions in the ComEd
          and PECO service territories in 2003 resulting in net volume and price
          increases of $22 million,
     o    increases of $63 million for generation  from plants  acquired  during
          2002 resulting in higher market sales,
     o    increased  revenue  from  ComEd  of $31  million  associated  with the
          adoption of SFAS No. 143, which was not included in revenue in 2002,
     o    mark-to-market  gains on  hedging  activities  of $1  million  in 2003
          compared to $10 million in 2002, and
     o    additional  nuclear fuel amortization of $16 million in 2003 resulting
          from under performing fuel at the Quad Cities Unit 1.

     The  changes in  operating  income,  other than  changes in revenue  net of
purchased  power  and fuel  expense,  for the six  months  ended  June 30,  2003
compared to the same period in 2002, included the following:

     o    increased  accretion  expense of $103  million due to the  adoption of
          SFAS No. 143, partially offset by reduced  decommissioning  expense of
          $64 million,
     o    higher  costs of $36 million for employee  medical,  pension and other
          employee  payroll and  benefit  costs in 2003,  partially  offset by a
          one-time executive severance charge of $19 million in 2002,
     o    increased  O&M costs of $38  million  due to asset  acquisitions  made
          during  2002  and a $5  million  impairment  charge  recorded  in 2003
          related to Mystic Station Units 4, 5, and 6,
     o    reduced  refueling outage costs of $53 million,  including $17 million
          at one of  Generation's  co-owned  facilities,  resulting  from  fewer
          refueling outage days in 2003,




                                       78
<PAGE>

     o    additional depreciation of $10 million due to capital additions placed
          in service and plant acquisitions made during 2002 and $16 million due
          to plant acquisitions made after the second quarter of 2002, partially
          offset by a $10 million reduction to depreciation  expense due to life
          extensions made in 2002, and
     o    reduction in worker's compensation expense of $8 million,  compared to
          2002.

     The changes in income before income taxes and cumulative  effect of changes
in accounting  principles for the six months ended June 30, 2003 compared to the
same period in 2002, included the following:

     o    a pre-tax  impairment  charge of $200 million  related to Generation's
          equity investment in Sithe,
     o    increased  decommissioning  trust  investment  income of $33  million,
          which is almost  entirely  offset with accretion  expense  recorded in
          O&M,
     o    increased  equity  in  earnings  of  unconsolidated  affiliates  of $5
          million, and
     o    increased  interest  expense of $10 million  primarily  due to reduced
          capitalized  interest in 2003 in addition to interest  incurred on the
          note payable to Sithe.

     Generation's  effective  income tax rate was 44.2% for the six months ended
June 30, 2003  compared to 39.0% for the same period in 2002.  This increase was
primarily   attributable  to  the  impact  of  the  impairment  of  Generation's
investment  in Sithe,  as well as an  increase  in taxes  related to the nuclear
decommissioning trust funds.


     Cumulative effect of changes in accounting  principles  recorded in the six
months  ended June 30, 2003 and 2002  included  income of $108  million,  net of
income  taxes,  recorded in the first quarter of 2003 related to the adoption of
SFAS No. 143 and income of $13 million,  net of income  taxes,  recorded in 2002
related to the adoption of SFAS No. 141, "Business  Combinations" (SFAS No. 141)
and SFAS No. 142. See Note 2 of the  Condensed  Combined  Notes to  Consolidated
Financial Statements for further discussion of these effects.





                                       79
<PAGE>

Generation Operating Statistics

     Generation's  sales and the supply of these  sales,  excluding  the trading
portfolio, were as follows:

<TABLE>
<CAPTION>
                                                                    Six Months Ended June 30,
                                                                    -------------------------
     Sales (in GWhs)                                                        2003         2002     Variance     % Change
-----------------------------------------------------------------------------------------------------------------------
<S>                                                                       <C>          <C>          <C>          <C>
     Energy Delivery and Exelon Energy Company                            57,463       58,649       (1,186)      (2.0%)
     Market Sales                                                         51,264       39,913       11,351       28.4%
-----------------------------------------------------------------------------------------------------------
     Total Sales                                                         108,727       98,562       10,165       10.3%
===========================================================================================================

                                                                    Six Months Ended June 30,
                                                                    -------------------------
     Supply of Sales (in GWhs)                                              2003         2002     Variance     % Change
-----------------------------------------------------------------------------------------------------------------------
     Nuclear Generation (1)                                               58,949       56,309        2,640        4.7%
     Purchases - non-trading portfolio (2)                                39,373       36,071        3,302        9.2%
     Fossil and Hydro Generation                                          10,405        6,182        4,223       68.3%
-----------------------------------------------------------------------------------------------------------
     Total Supply                                                        108,727       98,562       10,165       10.3%
===========================================================================================================
<FN>
     (1) Excluding AmerGen.
     (2) Including purchased power agreements with AmerGen.
</FN>
</TABLE>

     Trading volume of 17,446 GWhs and 22,805 GWhs for the six months ended June
30,  2003 and  2002,  respectively,  is not  included  in the table  above.  The
decrease  in trading  volume is a result of reduced  volumetric  and VAR trading
limits in 2003,  which are set by the Risk Management  Committee and approved by
the Board of Directors.

     Generation's  average  margin and other  operating  data for the six months
ended June 30, 2003 and 2002 were as follows:

<TABLE>
<CAPTION>
                                                                              Six Months Ended June 30,
                                                                              -------------------------
      ($/MWh)                                                                   2003               2002        % Change
------------------------------------------------------------------------------------------------------------------------
<S>                                                                      <C>              <C>                     <C>
     Average Revenue
         Energy Delivery and Exelon Energy Company                       $     32.06      $      31.35            2.3%
         Market Sales                                                          35.94             29.44           22.1%
         Total - excluding the trading portfolio                               33.89             30.58           10.8%

     Average Supply Cost (1) - excluding the trading portfolio           $     20.58      $      17.78           15.7%

     Average Margin - excluding the trading portfolio                    $     13.31      $      12.80            4.0%
------------------------------------------------------------------------------------------------------------------------
<FN>
(1)      Average supply cost includes purchased power and fuel costs.
</FN>
</TABLE>


<TABLE>
<CAPTION>
                                                                                              Six Months Ended June 30,
                                                                                              -------------------------
                                                                                                   2003            2002
---------------------------------------------------------------------------------------------------------------------------
<S>                                                                                          <C>             <C>
     Nuclear fleet capacity factor (1)                                                              94.2%           91.2%
     Nuclear fleet production cost per MWh (1)                                                $    12.40      $    13.38
     Average purchased power cost for wholesale operations per MWh                            $    41.71      $    36.76
---------------------------------------------------------------------------------------------------------------------------
<FN>
     (1) Including AmerGen and excluding Salem.
</FN>
</TABLE>

     The  factors  below  contributed  to the overall  increase in  Generation's
average  margin for the six months  ended June 30,  2003 as compared to the same
period in 2002.




                                       80
<PAGE>

     Generation's average revenue per MWh was affected by:

     o    increased  weighted  average on and off-peak prices per MWh for supply
          agreements with ComEd,
     o    higher prices per MWh on sales under supply agreements with PECO, and
     o    higher market prices.

     Generation's supply mix changed as a result of:

     o    increased  nuclear  generation  due to a lower number of refueling and
          unplanned outages during 2003 compared to 2002,
     o    increased  fossil  generation due to the effect of the  acquisition of
          two  generating  plants  in Texas in April  2002,  and the  Sithe  New
          England  (currently  known as Exelon New England)  plants  acquired in
          November  2002,  which in total account for an increase of 2,995 GWhs,
          and
     o    increased quantity of purchased power at higher prices.

     Higher nuclear capacity factors and decreased nuclear  production costs are
primarily  due to 50 fewer  planned  refueling  outage days,  resulting in a $36
million  decrease  in outage  costs,  in the six months  ended June 30,  2003 as
compared to the same period in 2002. Additionally, the six months ended June 30,
2003 included 11 unplanned  outages compared to 13 unplanned  outages during the
six months ended June 30, 2002.

     Results of Operations - Enterprises

<TABLE>
<CAPTION>
                                                                     Six Months Ended June 30,
                                                                     -------------------------
                                                                            2003         2002     Variance     % Change
------------------------------------------------------------------------------------------------------------------------
<S>                                                                     <C>          <C>          <C>            <C>
     Operating revenues                                                 $  1,022     $    966         $ 56          5.8%
     Operating loss                                                          (84)         (50)         (34)        68.0%
     Income (loss) before income taxes and cumulative effect
       of changes in accounting principles                                  (125)          95         (220)         n.m.
     Income (loss) before cumulative effect of changes in
       accounting principles                                                 (78)          55         (133)         n.m.
     Net loss                                                                (79)        (188)         109        (58.0%)
------------------------------------------------------------------------------------------------------------------------
     n.m. - not meaningful
</TABLE>

     The changes in  Enterprises'  operating  loss for the six months ended June
30, 2003 compared to the same period in 2002, included the following:

     o    an impairment charge of $47 million before income taxes related to the
          goodwill of InfraSource, Inc. The applicable assets and liabilities of
          InfraSource,  Inc. were  classified as held for sale during the second
          quarter of 2003,
     o    lower  operating  income at InfraSource  Inc. of $5 million  primarily
          resulting  from a decrease  in the  electric  line of  business of $13
          million  and a $2 million  decrease  in  metering  services  partially
          offset by lower  costs of $7 million in the  telecom  line of business
          and $3 million from bad debt expense recorded in 2002,
     o    higher  operating  income  at  Exelon  Energy  Company  of $6  million
          resulting  from lower  operating  expense from the  discontinuance  of
          retail sales in the PJM region  including  2002 costs for  accelerated
          depreciation of $14 million and general and administrative




                                       81
<PAGE>

          costs of $3 million.  These costs were partially offset by lower gross
          margins of $11 million in 2003. The lower gross margins  resulted from
          the  reversal  of  mark-to-market   adjustments  of  $11  million  and
          additional  gas  supply  costs  of  $11  million  attributable  to gas
          purchases at high rates in the Northeast,  partially  offset by higher
          gross margins of $8 million in the Midwest  attributable  to increased
          unit margins and higher volumes,  and $2 million  favorable related to
          the wind-down of a contract,
     o    higher operating income at Exelon Thermal of $4 million resulting from
          lower production  costs, and
     o    reductions in general and administrative expenses of $9 million.

     The changes in income (loss) before income taxes and  cumulative  effect of
changes in accounting principles for the six months ended June 30, 2003 compared
to the same period in 2002, include the following additional impacts:

     o    a pre-tax gain of $198  million in 2002 and higher  equity in earnings
          of  unconsolidated  affiliates  of $4 million in 2003  primarily  as a
          result of the  discontinuation  of losses  on the  investment  in AT&T
          Wireless due to the sale of the  investment  in the second  quarter of
          2002, and
     o    an  impairment  charge in 2003 of  energy-related  investments  of $22
          million,  communications investments of $13 million, and $5 million of
          software-related investments due to an other-than-temporary decline in
          value,   partially   offset  by  an  impairment   charge  in  2002  of
          communications investments of $29 million,  energy-related investments
          of $11 million and a net impairment of other assets of $4 million.

     The  effective  income tax rate was 37.6% for the six months ended June 30,
2003,  compared  to 42.1% for the same  period  in 2002.  This  decrease  in the
effective tax rate was  attributable to lower effective  income tax rates on the
impairment  charges  compared  to the  tax  rate  on the  gain  on the  sale  of
Enterprises' AT&T Wireless investment.

     The cumulative effect of a change in accounting  principle  recorded in the
first  quarter of 2003 due to the adoption of SFAS No. 143 reduced net income by
$1 million, net of income taxes. The cumulative effect of a change in accounting
principle recorded in the first quarter of 2002 for the adoption of SFAS No. 142
reduced  net  income by $243  million,  net of income  taxes  (see Note 2 of the
Condensed Combined Notes to Consolidated Financial Statements).

     Enterprises  continues  to  pursue  the  divestiture  of other  businesses;
however, it may be unable to successfully  implement its divestiture strategy of
certain  businesses  for a number of reasons,  including  an inability to locate
appropriate  buyers or to negotiate  acceptable terms for the  transactions.  In
addition,  the amount that Enterprises may realize from a divestiture is subject
to fluctuating  market conditions that may contribute to pricing and other terms
that are  materially  different  than expected and could result in a loss on the
sale. Timing of any divestitures may positively or negatively affect the results
of  operations as Exelon  expects  certain  businesses  to be  profitable  going
forward.




                                       82
<PAGE>

General

     Due to revenue needs in the states in which Exelon operates,  various state
income tax and fee increases  have been proposed or are being  contemplated.  If
these  changes  are  enacted,  they could  increase  Exelon's  state  income tax
expense.  At this time,  however,  Exelon cannot predict whether  legislation or
regulation  will be  introduced,  the  form of any  legislation  or  regulation,
whether  any  such  legislation  or  regulation  will  be  passed  by the  state
legislatures or regulatory bodies, and, if enacted, whether any such legislation
or regulation would be effective  retroactively or  prospectively.  As a result,
Exelon cannot  currently  estimate the effect of these potential  changes in tax
laws or regulation.

LIQUIDITY AND CAPITAL RESOURCES

     Exelon's businesses are capital intensive and require  considerable capital
resources.   These  capital  resources  are  primarily  provided  by  internally
generated  cash flows from Energy  Delivery and  Generation's  operations.  When
necessary, Exelon obtains funds from external sources in the capital markets and
through bank  borrowings.  Exelon's  access to external  financing at reasonable
terms  depends on  Exelon's  and its  subsidiaries'  credit  ratings and general
business  conditions,  as well as that of the utility  industry  in general.  If
these  conditions  deteriorate  to where Exelon no longer has access to external
financing  sources at  reasonable  terms,  Exelon  has access to a $1.5  billion
revolving  credit  facility  that  Exelon  currently  utilizes  to  support  its
commercial paper program. See the Credit Issues section of Liquidity and Capital
Resources for further discussion. Exelon primarily uses its capital resources to
fund capital requirements, including construction, to invest in new and existing
ventures,  to repay  maturing  debt and to pay common  stock  dividends.  Future
acquisitions  that Exelon may undertake may require  external  financing,  which
might include Exelon issuing common stock.

     In the second quarter of 2003,  Exelon progressed in its plans to implement
its new business  model referred to as The Exelon Way. The Exelon Way is focused
on  improving   operating  cash  flows  while  meeting   service  and  financial
commitments  through  improved  integration of operations and  consolidation  of
support  functions.  Exelon is working to meet its goals of  approximately  $300
million of annual cash savings  beginning in 2004 and increasing the annual cash
savings to $600  million in 2006.  As part of the  implementation  of The Exelon
Way, Exelon anticipates  incurring expenses  associated with the rationalization
of certain business functions and employee  separation costs. These expenses may
be significant and are expected to be incurred during the remaining half of 2003
through 2005. However, these costs cannot be reasonably estimated at this time.

Cash Flows from Operating Activities

     Cash flows  provided by  operations  for the six months ended June 30, 2003
were $1.3  billion  compared  to $1.6  billion in the six months  ended June 30,
2002.  The decrease in cash flows was primarily  attributable  to a $229 million
decrease in working  capital and the $240 million funding of the pension benefit
obligation.  Energy  Delivery's  cash flow from operating  activities  primarily
results from sales of electricity and gas to a stable and diverse base of retail




                                       83
<PAGE>

customers at fixed prices.  Energy Delivery's future cash flows will depend upon
the ability to achieve cost savings in operations and the impact of the economy,
weather  and  customer  choice on its  revenues.  Generation's  cash  flows from
operating  activities  primarily  result  from the sale of  electric  energy  to
wholesale  customers,  including Energy Delivery and  Enterprises.  Generation's
future cash flow from  operating  activities  will depend upon future demand and
market prices for energy and the ability to continue to produce and supply power
at competitive  costs.  Although the amounts may vary from period to period as a
result of the  uncertainties  inherent in business,  Exelon  expects that Energy
Delivery and Generation will continue to provide a reliable and steady source of
internal cash flow from operations for the foreseeable future.

Cash Flows used in Investing Activities

     Cash flows used in investing  activities  for the six months ended June 30,
2003 were $1.0  billion,  compared to $1.3 billion for the six months ended June
30, 2002. The decrease in cash flows is primarily attributable to a reduction in
plant  acquisition  costs of $443  million  as a result  of the  acquisition  of
generating  plants  during the six months  ended June 30,  2002,  a reduction of
capital  expenditures of $9 million,  the receipt of liquidating  damages of $86
million  from  Raytheon  during the six months  ended June 30,  2003,  partially
offset by increased  investments in nuclear  decommissioning  trust funds of $52
million and a reduction of proceeds from the sale of investments of $279 million
primarily  attributable to the sale of AT&T Wireless during the six months ended
June 30, 2002. Capital expenditures by business segment for the six months ended
June 30, 2003 and 2002 were as follows:

<TABLE>
<CAPTION>
                                                                                        Six Months Ended June 30,
                                                                                        -------------------------
                                                                                            2003              2002
------------------------------------------------------------------------------------------------------------------
<S>                                                                                     <C>                <C>
Energy Delivery                                                                         $    487           $   495
Generation                                                                                   424               475
Enterprises                                                                                   11                28
Corporate and other                                                                           11                30
------------------------------------------------------------------------------------------------------------------
Total capital expenditures (net of liquidated damages received)                         $    933           $ 1,028
==================================================================================================================
</TABLE>

     Energy Delivery's capital expenditures for 2003 reflect the continuation of
efforts to further improve the reliability of its  distribution  system.  Exelon
anticipates  that  Energy  Delivery's  capital  expenditures  will be  funded by
internally generated funds, borrowings, the issuance of preferred securities, or
capital contributions from Exelon.

     Generation's  capital  expenditures  for 2003 reflect the  construction  of
three Exelon New England generating  facilities with projected capacity of 2,421
MWs of energy,  additions  to and  upgrades  of existing  facilities  (including
nuclear refueling  outages),  and nuclear fuel. During the six months ended June
30, 2003, Generation received $86 million of liquidated damages from Raytheon as
a result of  Raytheon  not  meeting  the  expected  completion  date and certain
contractual  performance criteria in connection with Raytheon's  construction of
Exelon New England's  Mystic 8 and 9 and Fore River  generating  facilities.  In
February  2002,  Generation  entered into an agreement to loan AmerGen up to $75
million at an interest  rate of one-month  LIBOR plus 2.25%.  In July 2002,  the
loan agreement and the loan were increased to $100 million and the maturity date
was  extended  to July 1,  2003.  As of June 30,  2003,  the loan has




                                       84
<PAGE>

been fully  repaid by AmerGen.  Exelon  anticipates  that  Generation's  capital
expenditures will be funded by internally generated funds, borrowings or capital
contributions from Exelon.

     Enterprises'  capital  expenditures for 2003 are primarily for additions of
equipment. All of Enterprises' capital expenditures are expected to be funded by
internally generated funds, capital contributions or borrowings from Exelon.

Cash Flows used in Financing Activities

     Cash flows  used in  financing  activities  were $284  million  for the six
months ended June 30, 2003 compared to $142 million for the same period in 2002.
The  increase  in cash flows is  primarily  attributable  to debt and  preferred
securities  issuances  of $2.1  billion and an  increase  of  proceeds  from the
exercise of employee  stock  options over the same period in 2002 of $31 million
partially offset by retirements and redemptions of debt and preferred securities
of $1.9 billion,  the $210 million  payment of the  acquisition  note payable to
Sithe and increased  interest rate swap settlement  payments of $41 million over
the  same  period  in  2002.  See  Note 9 of the  Condensed  Combined  Notes  to
Consolidated  Financial  Statements for further  discussion of Exelon's debt and
preferred securities financing activities in 2003.

Credit Issues

     Exelon meets its short-term  liquidity  requirements  primarily through the
issuance of commercial  paper by the Exelon  corporate  holding  company (Exelon
Corporate) and by ComEd,  PECO and Generation.  Exelon  Corporate  participates,
along with ComEd,  PECO and  Generation,  in a $1.5  billion  unsecured  364-day
revolving  credit  facility with a group of banks.  The credit  facility  became
effective on November  22, 2002 and  includes a term-out  option that allows any
outstanding borrowings at the end of the revolving credit period to be repaid on
November 21, 2004.  Exelon  Corporate  may increase or decrease the sublimits of
each of the participants upon written  notification to the banks. As of June 30,
2003, Exelon  Corporate's  sublimit was $1.0 billion,  ComEd's was $100 million,
PECO's was $400  million and the sublimit for  Generation  was zero.  The credit
facility is used  principally to support the commercial paper programs of Exelon
Corporate,  ComEd, PECO and Generation.  At June 30, 2003, Exelon's Consolidated
Balance Sheet reflected $581 million of commercial  paper  outstanding.  For the
six months ended June 30, 2003,  the average  interest rate on notes payable was
approximately 1.38%.





                                       85
<PAGE>

     The credit facility requires Exelon  Corporate,  ComEd, PECO and Generation
to maintain a minimum cash from  operations  to interest  expense  ratio for the
twelve-month  period  ended on the last day of any quarter.  The ratios  exclude
revenues and interest  expenses  attributable to  securitization  debt,  certain
changes  in  working   capital,   distributions   on  preferred   securities  of
subsidiaries and, in the case of Exelon Corporate and Generation,  revenues from
Exelon New England  and  interest  on the debt of Exelon New  England's  project
subsidiaries.  Exelon Corporate is measured at the Exelon consolidated level. At
June 30, 2003, Exelon  Corporate,  ComEd, PECO and Generation were in compliance
with the  credit  agreement  thresholds.  The  following  table  summarizes  the
threshold  reflected in the credit  agreement that the ratio cannot be less than
for the twelve-month period ended June 30, 2003:

<TABLE>
<CAPTION>
                                             Exelon Corporate             ComEd             PECO        Generation
------------------------------------------------------------------------------------------------------------------
<S>                                                 <C>              <C>             <C>               <C>
Credit agreement threshold                          2.65 to 1         2.25 to 1        2.25 to 1         3.25 to 1
------------------------------------------------------------------------------------------------------------------
</TABLE>

     To provide an additional short-term borrowing option that will generally be
more  favorable  to  the  borrowing  participants  than  the  cost  of  external
financing,  Exelon operates an  intercompany  money pool.  Participation  in the
money pool is subject to authorization by Exelon's corporate treasurer.  ComEd's
subsidiary,  Commonwealth Edison Company of Indiana,  Inc., PECO, Generation and
Exelon  Business  Services  Company (BSC) may  participate  in the money pool as
lenders and borrowers, and Exelon Corporate and ComEd as lenders.  Contributions
to and permitted  borrowings  from the money pool are  predicated on whether the
contributions   and   borrowings   result  in  economic   benefits  to  all  the
participants.  Interest on  borrowings  is based on  short-term  market rates of
interest,  or, if from an external source,  specific borrowing rates. During the
six months ended June 30, 2003,  ComEd had various loans to Generation under the
money pool. The maximum  amount of loans  outstanding at any time during the six
months  ended  June  30,  2003  was  $342  million.  As of June  30,  2003,  the
outstanding loan balance was $165 million.

     Exelon Boston Generating,  LLC (EBG), an indirect subsidiary of Generation,
has approximately  $1.1 billion of debt outstanding under a $1.25 billion credit
facility  (EBG  Facility)  at June 30,  2003.  The EBG Facility was entered into
primarily  to  finance  the  construction  of the  Mystic 8 and 9 and Fore River
generating  units.  The EBG Facility  requires that all of the projects  achieve
"Project  Completion," as defined in the EBG Facility (Project  Completion),  by
June 12, 2003.  On June 11,  2003,  EBG  negotiated  an extension of the Project
Completion  date to July 11, 2003.  On July 3, 2003,  the lenders  under the EBG
Facility  and EBG  executed a letter  agreement as a result of which the lenders
are  precluded  during the period  July 11,  2003  through  August 29, 2003 from
exercising  any  remedies  resulting  from the failure of all of the projects to
achieve Project  Completion.  At that time, EBG stated that it would continue to
monitor the projects,  assess all of its options  relating to the projects,  and
continue  discussions  with  the  lenders.  Mystic  8 and 9  are  in  commercial
operation,  although  construction  has not  progressed  to the point of Project
Completion. Construction of Fore River is substantially complete and the unit is
currently  undergoing  testing.  EBG does not anticipate  that the projects will
achieve Project  Completion by August 29, 2003. The EBG Facility is non-recourse
to Exelon and Generation and an event of default under the EBG Facility does not
constitute an event of default under any other debt instruments of Exelon or its
subsidiaries.




                                       86
<PAGE>

     As  a  result  of  Exelon's  continuing  evaluation  of  the  projects  and
discussions  with the lenders in July 2003,  Exelon has commenced the process of
an  orderly  transition  out of the  ownership  of EBG  and  the  projects.  The
transition will take place in a manner that complies with applicable  regulatory
requirements.  For a period of time,  Exelon  expects  to  continue  to  provide
administrative and operational services to EBG in its operation of the projects.
Exelon  informed  the lenders of Exelon's  decision to exit and that it will not
provide  additional  funding to the  projects  beyond its  existing  contractual
obligations. Exelon cannot predict the timing of the transition.

     Exelon  expects  Generation  will incur an  impairment  of its EBG  related
assets, which, in aggregate, could reach approximately $550 million after income
taxes.

     The debt outstanding  under the EBG Facility of approximately  $1.1 billion
at June 30,  2003 is  reflected  in  Exelon's  Consolidated  Balance  Sheet as a
current liability.

     On June 13,  2003,  Generation  closed on a $550 million  revolving  credit
facility.  Generation  used the  facility  to make the  first  payment  to Sithe
relating to the $536 million note that was used to purchase the EBG  facilities.
This note was restructured in June 2003 to provide for a payment of $210 million
of the principal on June 16, 2003 and payment of the remaining  principal on the
earlier of December 1, 2003 or change of control.

     Exelon's  access to the capital  markets,  including the  commercial  paper
market,  and its  financing  costs in those  markets  depend  on the  securities
ratings of the entity that is accessing  the capital  markets.  None of Exelon's
borrowings is subject to default or  prepayment as a result of a downgrading  of
securities  ratings although such a downgrading could increase fees and interest
charges  under  Exelon's $1.5 billion  credit  facility and certain other credit
facilities.  From time to time,  Exelon  enters into energy  commodity and other
contracts that require the maintenance of investment  grade ratings.  Failure to
maintain  investment grade ratings would allow  counterparties to certain energy
commodity  contracts to terminate the contracts and settle the transactions on a
net present value basis.

     Exelon  obtained an order from the United  States  Securities  and Exchange
Commission  (SEC)  under PUHCA  authorizing  through  March 31,  2004  financing
transactions,  including  the issuance of common  stock,  preferred  securities,
long-term  debt and  short-term  debt,  in an aggregate  amount not to exceed $4
billion.  As of June 30, 2003,  there was $2.3  billion of  financing  authority
remaining under the SEC order.  Exelon's request for an additional $4 billion in
financing  authorization  is pending  with the SEC.  The  current  order  limits
Exelon's  short-term  debt  outstanding  to $3 billion  of the $4 billion  total
financing  authority.  Exelon's  request  that  the  short-term  debt  sub-limit
restriction be eliminated is pending with the SEC. The SEC order also authorized
Exelon to issue guarantees of up to $4.5 billion outstanding at any one time. At
June 30, 2003,  Exelon had provided  $1.7  billion of  guarantees  under the SEC
order. See Contractual Obligations, Commercial Commitments and Off-Balance Sheet
Obligations in this section for further discussion of guarantees.  The SEC order
requires  Exelon  and  ComEd to  maintain  a ratio  of  common  equity  to total
capitalization (including securitization debt) on and after June 30, 2002 of not
less than 30%. At June 30, 2003,  Exelon and ComEd's  common



                                       87
<PAGE>

equity ratios were 34% and 46%, respectively.  Exelon and ComEd expect that they
will maintain a common equity ratio of at least 30%.

     Under PUHCA, Exelon, ComEd, PECO and Generation can pay dividends only from
retained,  undistributed  or current  earnings.  However,  the SEC order granted
permission to ComEd, and to Exelon, to the extent Exelon receives dividends from
ComEd paid from ComEd additional  paid-in-capital,  to pay up to $500 million in
dividends  out of  additional  paid-in  capital,  although  Exelon  may  not pay
dividends out of paid-in capital after December 31, 2002 if its common equity is
less than 30% of its total capitalization. At June 30, 2003, Exelon had retained
earnings of $2.5 billion,  including  ComEd's retained earnings of $767 million,
PECO's retained earnings of $455 million and Generation's undistributed earnings
of $1.1  billion.  Exelon is also  limited by order of the SEC under PUHCA to an
aggregate  investment of $4 billion in exempt  wholesale  generators  (EWGs) and
foreign utility  companies  (FUCOs).  At June 30, 2003, Exelon had invested $2.2
billion in EWGs,  leaving $1.8 billion of investment  authority under the order.
Exelon's request for an additional $1.5 billion in EWG investment  authorization
is pending with the SEC.

Contractual Obligations, Commercial Commitments and Off-Balance Sheet
Obligations

     Contractual  obligations  represent cash obligations that are considered to
be firm commitments and commercial  commitments  represent commitments triggered
by future events. Exelon's contractual obligations and commercial commitments as
of June 30,  2003 were  materially  unchanged,  other than the normal  course of
business,  from the  amounts  set  forth in the 2002 Form  10-K  except  for the
following:

     o    On March  3,  2003,  ComEd  entered  into an  agreement  with  various
          Illinois  electric  retail market  suppliers,  key customer groups and
          governmental parties regarding several matters affecting ComEd's rates
          for electric service (Agreement). The Agreement addressed, among other
          things,  issues related to ComEd's delivery  services rate proceeding,
          market value index  proceeding,  the process for  competitive  service
          declarations for large-load customers and an extension of the PPA with
          Generation.  During the second  quarter of 2003, the ICC issued orders
          consistent with the Agreement, which is now effective.

               The Agreement provides for a modification of the methodology used
          to determine  ComEd's market value energy credit.  That credit is used
          to determine the price for specified  market-based  rate offerings and
          the amount of the CTC that ComEd is allowed to collect from  customers
          who select an ARES or the PPO. The credit was adjusted upwards through
          agreed upon "adders"  which took effect in June 2003 and will have the
          effect of  reducing  ComEd's CTC  charges to  customers.  Prior to the
          Agreement, all CTC charges were subject to annual mid-year adjustments
          based on the forward  market prices for on-peak  energy and historical
          market prices for off-peak  energy.  The  Agreement  provides that the
          annual market price  adjustment will reflect forward market prices for
          energy, rather than historical, and allows customers an option to lock
          in current  levels of CTC charges for  multi-year  periods  during the
          regulatory  transition  period ending in 2006.  These changes  provide
          customers  and suppliers  greater price  certainty and are expected to
          result in an increase in the number of customers  electing to purchase
          energy from alternate suppliers.




                                       88
<PAGE>

               The annual market price  adjustments to the CTC effective in June
          2002 and June 2003 had the effect of significantly  increasing the CTC
          charge in June 2002, and subsequently  significantly  reducing the CTC
          charge in June 2003.  In 2002,  ComEd  collected  $306  million in CTC
          revenue.  Based on the changes in the CTC as part of the Agreement and
          on current assumptions about the competitive price of delivered energy
          and customers' choice of electric  supplier,  ComEd estimates that CTC
          revenue will be approximately  $300 million in 2003 and  approximately
          $140 million for each of the years 2004 through 2006.

               During  the first  quarter  of 2003,  ComEd  recorded a charge to
          earnings  associated  with  the  funding  of  specified  programs  and
          initiatives  associated with the Agreement of $51 million on a present
          value basis before  income taxes.  This amount is partially  offset by
          the  reversal  of  a  $12  million   (before   income  taxes)  reserve
          established  in the  third  quarter  of 2002 for a  potential  capital
          disallowance in ComEd's delivery services rate proceeding and a credit
          of $10 million (before income taxes) related to the  capitalization of
          employee  incentive  payments  provided for in the  delivery  services
          order.  The net one-time charge for these items is $29 million (before
          income taxes).

     o    ComEd  and  PECO  have  entered  into  several  agreements  with a tax
          consultant  related to the filing of refund  claims with the  Internal
          Revenue  Service (IRS).  The fees for these  agreements are contingent
          upon a  successful  outcome  and are based  upon a  percentage  of the
          refunds  recovered from the IRS, if any. As such, ComEd and PECO would
          have positive net cash flows  related to these  agreements if any fees
          are paid to the tax  consultant.  These  potential  tax  benefits  and
          associated fees could be material to the financial  position,  results
          of operations and cash flows of Energy Delivery.  ComEd's tax benefits
          for periods  prior to the Merger  would be recorded as a reduction  of
          goodwill  pursuant to a  reallocation  of the Merger  purchase  price.
          Energy Delivery  cannot predict the timing of the final  resolution of
          these refund claims.

     o    See Note 9 to the Condensed  Combined Notes to Consolidated  Financial
          Statements  for  discussion  of material  changes in Exelon's debt and
          preferred securities obligations from those set forth in the 2002 Form
          10-K.

     o    Generation entered into a PPA dated June 26, 2003 with AmerGen.  Under
          the PPA, Generation has agreed to purchase 100% of energy generated by
          Oyster Creek  Nuclear Power Station  (Oyster  Creek)  through April 9,
          2009.  See Note 8 of the  Condensed  Combined  Notes  to  Consolidated
          Financial  Statements for commercial  commitments tables  representing
          Exelon's commitments not recorded on the balance sheet but potentially
          triggered by future events,  including  obligations to make payment on
          behalf of other  parties and  financing  arrangements  to secure their
          obligations.

     o    On  May  29,  2003,  Exelon  Fossil  Holdings,  Inc.,  a  wholly-owned
          subsidiary of Generation,  issued an  irrevocable  call notice for the
          35.2%  interest  in Sithe  owned by Apollo  Energy,  LLC and the 14.9%
          interest owned by subsidiaries of Marubeni Corporation. The total call
          price was based on the terms of the  existing  Put and Call  Agreement
          (PCA) among the parties and approximated $650 million. The transfer of
          ownership  requires various regulatory  approvals  including FERC, the
          state  environmental  agency in New Jersey, and expiration of the Hart
          Scott Rodino waiting period.

               Under the terms of the PCA,  the call must be funded  within  six
          months of the call  notice  being  issued.  Additionally,  because the
          Federal  Power  Act  restricts  Exelon's  ownership  of 50% or more of
          Qualifying  Facilities  (QFs),  the QFs owned by Sithe must be sold or
          restructured  before closing to preserve their QF status.  Despite the
          issuance of the call notice, Generation continues to pursue options to
          sell its investment in Sithe in its entirety.

     o    In June  2003,  Generation  entered  an  agreement  with USEC Inc.  to
          purchase  approximately $700 million of nuclear fuel from 2005 through
          2010.





                                       89
<PAGE>

COMMONWEALTH EDISON COMPANY
---------------------------

GENERAL

     ComEd operates in a single business  segment and its operations  consist of
the regulated sale of electricity and distribution and transmission  services in
northern Illinois.

RESULTS OF OPERATIONS

Three Months Ended June 30, 2003 Compared to Three Months Ended June 30, 2002

Significant Operating Trends - ComEd
<TABLE>
<CAPTION>
                                                             Three Months Ended June 30,
                                                             ---------------------------
                                                                       2003         2002     Variance     % Change
------------------------------------------------------------------------------------------------------------------
<S>                                                               <C>           <C>           <C>           <C>
OPERATING REVENUES                                                $   1,361     $  1,481      $  (120)      (8.1%)

OPERATING EXPENSES
    Purchased power                                                     533          553          (20)      (3.6%)
    Operating and maintenance                                           221          220            1        0.5%
    Depreciation and amortization                                        96          133          (37)     (27.8%)
    Taxes other than income                                              68           73           (5)      (6.8%)
------------------------------------------------------------------------------------------------------
         Total operating expenses                                       918          979          (61)      (6.2%)
------------------------------------------------------------------------------------------------------

OPERATING INCOME                                                        443          502          (59)     (11.8%)

OTHER INCOME AND DEDUCTIONS
    Interest expense                                                   (106)        (127)          21      (16.5%)
    Distributions on mandatorily redeemable preferred securities         (6)          (7)           1      (14.3%)
    Other, net                                                           12           14           (2)     (14.3%)
------------------------------------------------------------------------------------------------------
         Total other income and deductions                             (100)        (120)          20      (16.7%)
------------------------------------------------------------------------------------------------------

INCOME BEFORE INCOME TAXES                                              343          382          (39)     (10.2%)

INCOME TAXES                                                            138          151          (13)      (8.6%)
------------------------------------------------------------------------------------------------------
NET INCOME                                                        $     205     $    231        $ (26)     (11.3%)
======================================================================================================
</TABLE>

Net Income

     Net income  decreased  $26 million,  or 11% for the three months ended June
30,  2003 as  compared  to the same  period in 2002.  Net income was  negatively
impacted by lower operating  revenues net of purchased  power expense  primarily
due to unfavorable  weather and customers  purchasing energy from an ARES or the
PPO,  partially  offset  by lower  depreciation  and  amortization  expense  and
interest expense.




                                       90
<PAGE>

Operating Revenues

    ComEd's electric sales statistics are as follows:

<TABLE>
<CAPTION>
                                                    Three Months Ended June 30,
                                                    ---------------------------
Retail Deliveries - (in GWhs)                            2003              2002         Variance          % Change
-------------------------------------------------------------------------------------------------------------------
<S>                                                     <C>               <C>               <C>           <C>
Bundled Deliveries (1)
Residential                                             5,163             5,862             (699)         (11.9%)
Small Commercial & Industrial                           5,114             5,600             (486)          (8.7%)
Large Commercial & Industrial                           1,683             2,122             (439)         (20.7%)
Public Authorities & Electric Railroads                 1,333             1,685             (352)         (20.9%)
------------------------------------------------------------------------------------------------
                                                       13,293            15,269           (1,976)         (12.9%)
------------------------------------------------------------------------------------------------
Unbundled Deliveries (2)
ARES
----
Small Commercial & Industrial                           1,257             1,177               80            6.8%
Large Commercial & Industrial                           2,128             1,622              506           31.2%
Public Authorities & Electric Railroads                   247               181               66           36.5%
------------------------------------------------------------------------------------------------
                                                        3,632             2,980              652           21.9%
------------------------------------------------------------------------------------------------
PPO
---
Small Commercial & Industrial                             869               839               30            3.6%
Large Commercial & Industrial                           1,318             1,392              (74)          (5.3%)
Public Authorities & Electric Railroads                   531               274              257           93.8%
------------------------------------------------------------------------------------------------
                                                        2,718             2,505              213            8.5%
------------------------------------------------------------------------------------------------
    Total Unbundled Deliveries                          6,350             5,485              865           15.8%
------------------------------------------------------------------------------------------------
Total Retail Deliveries                                19,643            20,754           (1,111)          (5.4%)
================================================================================================
<FN>
(1)  Bundled service  reflects  deliveries to customers  taking electric service
     under tariffed rates.
(2)  Unbundled   service  reflects   customers   electing  to  receive  electric
     generation service from an ARES or the PPO.
</FN>
</TABLE>






                                       91
<PAGE>

<TABLE>
<CAPTION>
                                                    Three Months Ended June 30,
                                                    ---------------------------
Electric Revenue                                         2003              2002         Variance          % Change
------------------------------------------------------------------------------------------------------------------
<S>                                                <C>               <C>                 <C>               <C>
Bundled Revenues (1)
Residential                                        $      472        $      523          $   (51)          (9.8%)
Small Commercial & Industrial                             405               445              (40)          (9.0%)
Large Commercial & Industrial                              84               116              (32)         (27.6%)
Public Authorities & Electric Railroads                    81               102              (21)         (20.6%)
--------------------------------------------------------------------------------------------------
                                                        1,042             1,186             (144)         (12.1%)
--------------------------------------------------------------------------------------------------
Unbundled Revenues (2)
ARES
----
Small Commercial & Industrial                              32                30                2            6.7%
Large Commercial & Industrial                              43                32               11           34.4%
Public Authorities & Electric Railroads                     8                 5                3           60.0%
--------------------------------------------------------------------------------------------------
                                                           83                67               16           23.9%
--------------------------------------------------------------------------------------------------
PPO
---
Small Commercial & Industrial                              59                55                4            7.3%
Large Commercial & Industrial                              72                76               (4)          (5.3%)
Public Authorities & Electric Railroads                    28                17               11           64.7%
--------------------------------------------------------------------------------------------------
                                                          159               148               11            7.4%
--------------------------------------------------------------------------------------------------
Total Unbundled Revenues                                  242               215               27           12.6%
--------------------------------------------------------------------------------------------------
Total Electric Retail Revenues                          1,284             1,401             (117)          (8.4)%
Wholesale and Miscellaneous Revenue (3)                    77                80               (3)          (3.8)%
--------------------------------------------------------------------------------------------------
Total Electric Revenue                               $  1,361         $   1,481          $  (120)          (8.1)%
--------------------------------------------------------------------------------------------------
<FN>

(1)  Bundled revenue  reflects  deliveries to customers  taking electric service
     under  tariffed  rates,  which  include the cost of energy and the delivery
     cost of the transmission and the distribution of the energy.
(2)  Revenue from customers choosing an ARES includes a distribution  charge and
     a CTC  charge.  Transmission  charges  received  from ARES are  included in
     wholesale and miscellaneous  revenue.  Revenue from customers  choosing the
     PPO  includes  an  energy   charge  at  market  rates,   transmission   and
     distribution charges, and a CTC charge.
(3)  Wholesale and miscellaneous revenues include transmission revenue, sales to
     municipalities and other wholesale energy sales.

</FN>
</TABLE>

     The changes in electric retail revenues for the three months ended June 30,
2003, as compared to the same period in 2002, are attributable to the following:

<TABLE>
<CAPTION>
                                                                                                          Variance
-------------------------------------------------------------------------------------------------------------------
<S>                                                                                                        <C>
Weather                                                                                                    $  (108)
Customer choice                                                                                                (38)
Volume                                                                                                          25
Rate changes                                                                                                    (8)
Other effects                                                                                                   12
-------------------------------------------------------------------------------------------------------------------
Electric retail revenue                                                                                    $  (117)
===================================================================================================================
</TABLE>

o    Weather. The demand for electricity is impacted by weather conditions. Very
     warm  weather in summer  months and very cold  weather in other  months are
     referred  to  as  "favorable  weather  conditions"  because  these  weather
     conditions  result in  increased  sales of  electricity.  Conversely,  mild
     weather reduces demand.  The weather impact for the three months ended June
     30, 2003 was unfavorable compared to the same period in 2002 as a result of
     cooler spring  weather in 2003.  Cooling  degree-days  decreased 63% in the
     three  months  ended June 30, 2003  compared to the same period in 2002 and
     were 49% lower than normal.



                                       92
<PAGE>

o    Customer  Choice.  All ComEd  customers have the choice to purchase  energy
     from other  suppliers.  This choice generally does not impact the volume of
     deliveries,  but affects revenue collected from customers related to energy
     supplied  by  ComEd.  However,  as of June 30,  2003,  no ARES  has  sought
     approval from the ICC, and no electric  utilities  have chosen to enter the
     ComEd residential market for the supply of electricity.

          For the three  months  ended June 30,  2003,  the energy  provided  by
     alternative  suppliers was 3,632 GWhs or 18.5% as compared to 2,980 GWhs or
     14.4% for the three months ended June 30, 2002.

          The decrease in revenues  reflects  customers in Illinois  electing to
     purchase energy from an ARES or the PPO. As of June 30, 2003, the number of
     retail  customers  that had elected to purchase  energy from an ARES or the
     ComEd PPO was approximately 22,000 or 0.6% as compared to 22,700 or 0.6% as
     of  June  30,  2002.  MWhs  delivered  to  such  customers  increased  from
     approximately  5.5 million for the three  months ended June 30, 2002 to 6.3
     million for the three  months  ended June 30,  2003,  or from 26% to 32% of
     total  quarterly  retail  deliveries.   During  the  second  quarter  2003,
     approximately  2,500 customers  temporarily came back to the ComEd PPO as a
     result of an ARES no longer providing service in Illinois.

o    Volume.  Revenues  from  higher  delivery  volume,  exclusive  of  weather,
     increased due to an increased usage per customer, primarily residential and
     PPO.
o    Rate  Changes.  The  decrease  in  revenues  attributable  to rate  changes
     reflects  decreased  wholesale market prices which decreased energy revenue
     received under ComEd's PPO by $48 million. This was partially offset by the
     collection  of  additional  CTC's in 2003 by ComEd of $40 million due to an
     increase  in sales to  customers  choosing  an ARES or the ComEd PPO and an
     increase  in the  CTC  rates  due  to  lower  wholesale  market  prices  of
     electricity, net of increased mitigation factors. Starting in the June 2003
     billing cycle the increased  wholesale market price of electricity,  net of
     increased  mitigation  factors,  as a result of the Agreement  described in
     Note  4  of  the  Condensed   Combined  Notes  to  Consolidated   Financial
     Statements, decreases the collection of CTC's as compared to the respective
     period in 2002.

     Wholesale  and  miscellaneous  revenue for the three  months ended June 30,
2003 were comparable to the three months ended June 30, 2002.

Purchased Power

     Purchased power expense  decreased $20 million,  or 4% for the three months
ended June 30,  2003.  The  decrease in purchased  power  expense was  primarily
attributable to a $47 million decrease due to unfavorable weather conditions,  a
$21 million  decrease as a result of customers  choosing to purchase energy from
an ARES,  partially  offset by an increase of $10 million due to higher  volume,
$22  million  increase  due to  pricing  changes  related  to  ComEd's  PPA with
Generation   and  an  increase   of  $16  million   under  the  PPA  related  to
decommissioning  collections  associated  with the adoption of SFAS No. 143 that
were not  included  in  purchased  power in 2002.  The $16  million  increase in
purchased  power expense  related to SFAS No. 143 is offset by lower  regulatory
asset amortization.




                                       93
<PAGE>


Operating and Maintenance

     O&M expense  increased $1 million for the three months ended June 30, 2003.
The  increase  in O&M expense was  primarily  attributable  to an increase of $6
million in the  reserve  for  manufactured  gas plant  (MGP)  investigation  and
remediation as a result of increased costs of a MGP site in Oak Park,  Illinois,
partially offset by lower other O&M's.

Depreciation and Amortization

     Depreciation and amortization  expense  decreased $37 million,  or 28%, for
the three months ended June 30, 2003 as follows:

<TABLE>
<CAPTION>
                                                    Three Months Ended June 30,
                                                    ---------------------------
                                                         2003              2002         Variance          % Change
-------------------------------------------------------------------------------------------------------------------
<S>                                                  <C>              <C>                  <C>             <C>
Depreciation expense                                 $     76         $      92            $ (16)          (17.4%)
Recoverable transition costs amortization                  12                20               (8)          (40.0%)
Other amortization expense                                  8                21              (13)          (61.9%)
--------------------------------------------------------------------------------------------------
Total depreciation and amortization                  $     96         $     133            $ (37)          (27.8%)
==================================================================================================
</TABLE>

     The decrease in depreciation expense is primarily due to lower depreciation
rates effective July 1, 2002,  partially  offset by higher  property,  plant and
equipment  balances.  ComEd completed a depreciation study and implemented lower
depreciation  rates effective July 1, 2002. The new  depreciation  rates reflect
ComEd's  significant  construction  program  in  recent  years,  changes  in and
development of new  technologies,  and changes in estimated  plant service lives
since the last depreciation study. The annual reduction in depreciation  expense
is estimated to be approximately $100 million ($60 million, net of income taxes)
based  on  December  31,  2001  plant  balances.  As a  result  of  the  change,
depreciation  expense  decreased $24 million ($14 million,  net of income taxes)
for the three months ended June 30, 2003.

     Recoverable  transition  costs  amortization  decreased in the three months
ended June 30,  2003  compared  to the same  period in 2002.  The  decrease is a
result of the  extension of the rate freeze  through 2006 that  occurred in June
2002. ComEd expects to fully recover its recoverable transition costs regulatory
asset  balance of $153  million by 2006.  Consistent  with the  provision of the
Illinois legislation, regulatory assets may be recovered at amounts that provide
ComEd an earned return on common equity within the Illinois legislation earnings
threshold.

     The   decrease   in   other   amortization   primarily   relates   to   the
reclassification  of a regulatory asset for nuclear  decommissioning as a result
of the  adoption of SFAS No. 143 in 2003 (see Note 2 of the  Condensed  Combined
Notes  to  Consolidated  Financial  Statements).  This  decrease  is  offset  by
increased purchased power expense from Generation.

Taxes Other Than Income

     Taxes  other than  income  decreased  by $5 million or 7%, as a result of a
2003 refund of $5 million for  Illinois  Electricity  Distribution  Taxes,  a $5
million  decrease in other taxes  partially  offset by a $5 million  increase in
Illinois Public Utility Fund taxes, which were not charged in 2002.





                                       94
<PAGE>

Interest Charges

     Interest  charges  consist  of  interest   expense  and   distributions  on
mandatorily  redeemable  preferred  securities.  Interest charges  decreased $21
million,  or 17%,  for the  three  months  ended  June 30,  2003 as a result  of
scheduled  principal  payments and  refinancing  existing debt at lower interest
rates.

Other, Net

     Other, net decreased by $2 million for the three months ended June 30, 2003
as compared to the same period in 2002.

Income Taxes

     The effective income tax rate was 40.2% for the three months ended June 30,
2003, compared to 39.5% for the three months ended June 30, 2002.


     Six Months Ended June 30, 2003 Compared to Six Months Ended June 30, 2002

Significant Operating Trends - ComEd
<TABLE>
<CAPTION>
                                                               Six Months Ended June 30,
                                                               -------------------------
                                                                       2003         2002     Variance     % Change
-------------------------------------------------------------------------------------------------------------------
<S>                                                               <C>           <C>           <C>           <C>
OPERATING REVENUES                                                $   2,785     $  2,796      $   (11)      (0.4%)

OPERATING EXPENSES
    Purchased power                                                   1,110        1,091           19        1.7%
    Operating and maintenance                                           483          457           26        5.7%
    Depreciation and amortization                                       190          268          (78)     (29.1%)
    Taxes other than income                                             148          146            2        1.4%
-------------------------------------------------------------------------------------------------------
         Total operating expenses                                     1,931        1,962          (31)      (1.6%)
-------------------------------------------------------------------------------------------------------

OPERATING INCOME                                                        854          834           20        2.4%

OTHER INCOME AND DEDUCTIONS
    Interest expense                                                   (215)        (252)          37      (14.7%)
    Distributions on mandatorily redeemable preferred securities        (14)         (15)           1       (6.7%)
    Other, net                                                           34           29            5       17.2%
-------------------------------------------------------------------------------------------------------
         Total other income and deductions                             (195)        (238)          43      (18.1%)
-------------------------------------------------------------------------------------------------------

INCOME BEFORE INCOME TAXES AND CUMULATIVE
  EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE                            659          596           63       10.6%

INCOME TAXES                                                            263          236           27       11.4%
-------------------------------------------------------------------------------------------------------

NET INCOME BEFORE CUMULATIVE EFFECT OF
  A CHANGE IN ACCOUNTING  PRINCIPLE                                     396          360           36       10.0%

CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING
  PRINCIPLE                                                               5           --            5        n.m.
-------------------------------------------------------------------------------------------------------
NET INCOME                                                        $     401     $    360         $ 41       11.4%
=======================================================================================================
n.m. - not meaningful
</TABLE>




                                       95
<PAGE>

Net Income

     Net income increased $41 million,  or 11% for the six months ended June 30,
2003 as compared to the same period in 2002. Net income was positively  impacted
by lower  depreciation  and  amortization  expense and lower  interest  expense,
partially  offset  by lower  operating  revenues  primarily  due to  unfavorable
weather and customers purchasing energy from an ARES or the PPO.

Operating Revenues

     ComEd's electric sales statistics are as follows:

<TABLE>
<CAPTION>
                                                      Six Months Ended June 30,
                                                      -------------------------
Retail Deliveries - (in GWhs)                            2003              2002         Variance          % Change
-------------------------------------------------------------------------------------------------------------------
<S>                                                    <C>               <C>                <C>            <C>
Bundled Deliveries (1)
Residential                                            12,049            12,271             (222)          (1.8%)
Small Commercial & Industrial                          10,741            11,049             (308)          (2.8%)
Large Commercial & Industrial                           3,167             4,078             (911)         (22.3%)
Public Authorities & Electric Railroads                 2,749             3,486             (737)         (21.1%)
-------------------------------------------------------------------------------------------------
                                                       28,706            30,884           (2,178)          (7.1%)
-------------------------------------------------------------------------------------------------
Unbundled Deliveries (2)
ARES
----
Small Commercial & Industrial                           2,606             2,181              425           19.5%
Large Commercial & Industrial                           3,960             3,008              952           31.6%
Public Authorities & Electric Railroads                   529               319              210           65.8%
-------------------------------------------------------------------------------------------------
                                                        7,095             5,508            1,587           28.8%
-------------------------------------------------------------------------------------------------
PPO
---
Small Commercial & Industrial                           1,662             1,602               60            3.7%
Large Commercial & Industrial                           2,750             2,703               47            1.7%
Public Authorities & Electric Railroads                 1,069               517              552          106.8%
-------------------------------------------------------------------------------------------------
                                                        5,481             4,822              659           13.7%
-------------------------------------------------------------------------------------------------
    Total Unbundled Deliveries                         12,576            10,330            2,246           21.7%
-------------------------------------------------------------------------------------------------
Total Retail Deliveries                                41,282            41,214               68            0.2%
=================================================================================================
<FN>
(1)  Bundled service  reflects  deliveries to customers  taking electric service
     under tariffed rates.
(2)  Unbundled   service  reflects   customers   electing  to  receive  electric
     generation service from an ARES or the PPO.
</FN>
</TABLE>





                                       96
<PAGE>


<TABLE>
<CAPTION>
                                                      Six Months Ended June 30,
                                                      -------------------------
Electric Revenue                                         2003              2002         Variance          % Change
------------------------------------------------------------------------------------------------------------------
<S>                                                <C>               <C>                 <C>               <C>
Bundled Revenues (1)
Residential                                        $    1,018        $    1,041          $   (23)          (2.2%)
Small Commercial & Industrial                             802               836              (34)          (4.1%)
Large Commercial & Industrial                             158               218              (60)         (27.5%)
Public Authorities & Electric Railroads                   165               194              (29)         (14.9%)
-------------------------------------------------------------------------------------------------
                                                        2,143             2,289             (146)          (6.4%)
-------------------------------------------------------------------------------------------------
Unbundled Revenues (2)
ARES
----
Small Commercial & Industrial                              73                43               30           69.8%
Large Commercial & Industrial                              91                41               50          122.0%
Public Authorities & Electric Railroads                    17                 7               10          142.9%
-------------------------------------------------------------------------------------------------
                                                          181                91               90           98.9%
-------------------------------------------------------------------------------------------------
PPO
---
Small Commercial & Industrial                             109                98               11           11.2%
Large Commercial & Industrial                             144               140                4            2.9%
Public Authorities & Electric Railroads                    55                29               26           89.7%
-------------------------------------------------------------------------------------------------
                                                          308               267               41           15.4%
-------------------------------------------------------------------------------------------------
Total Unbundled Revenues                                  489               358              131           36.6%
-------------------------------------------------------------------------------------------------
Total Electric Retail Revenues                          2,632             2,647              (15)          (0.6%)
Wholesale and Miscellaneous Revenue (3)                   153               149                4            2.7%
-------------------------------------------------------------------------------------------------
Total Electric Revenue                               $  2,785         $   2,796            $ (11)          (0.4%)
=================================================================================================
<FN>
(1)  Bundled revenue  reflects  deliveries to customers  taking electric service
     under  tariffed  rates,  which  include the cost of energy and the delivery
     cost of the transmission and the distribution of the energy.
(2)  Revenue from customers choosing an ARES includes a distribution  charge and
     a CTC  charge.  Transmission  charges  received  from ARES are  included in
     wholesale and miscellaneous  revenue.  Revenue from customers  choosing the
     PPO  includes  an  energy   charge  at  market  rates,   transmission   and
     distribution charges, and a CTC charge.
(3)  Wholesale and miscellaneous revenues include transmission revenue, sales to
     municipalities and other wholesale energy sales.
</FN>
</TABLE>

     The changes in electric  retail  revenues for the six months ended June 30,
2003, as compared to the same period in 2002, are attributable to the following:

<TABLE>
<CAPTION>
                                                                                                          Variance
------------------------------------------------------------------------------------------------------------------
<S>                                                                                                        <C>
Customer choice                                                                                            $  (77)
Rate changes                                                                                                   75
Weather                                                                                                       (54)
Volume                                                                                                         32
Other effects                                                                                                   9
------------------------------------------------------------------------------------------------------------------
Electric retail revenue                                                                                    $  (15)
==================================================================================================================
</TABLE>

o    Customer Choice.  The decrease in revenues  reflects  customers in Illinois
     electing to purchase energy from an ARES or the PPO.

          For the six  months  ended  June 30,  2003,  the  energy  provided  by
     alternative  suppliers was 7,095 GWhs or 17.2% as compared to 5,508 GWhs or
     13.4% for the six months ended June 30, 2002.

          As of June 30, 2003,  the number of retail  customers that had elected
     to purchase energy from an ARES or the ComEd PPO was  approximately  22,000
     or 0.6% as compared to




                                       97
<PAGE>

     22,700  or 0.6% as of June  30,  2002.  MWhs  delivered  to such  customers
     increased from approximately 10.3 million for the six months ended June 30,
     2002 to 12.6 million for the six months ended June 30, 2003, or from 25% to
     30% of total  year-to-date  retail  deliveries.  During the second  quarter
     2003,  approximately 2,500 customers temporarily came back to the ComEd PPO
     as a result of an ARES no longer providing service in Illinois.

o    Rate  Changes.  The  increase  in  revenues  attributable  to rate  changes
     reflects  the  collection  of  additional  CTC's  in 2003 by  ComEd of $146
     million due to an increase  in sales to  customers  choosing an ARES or the
     ComEd PPO and an increase in CTC rates due to lower wholesale  market price
     of electricity, net of increased mitigation factors. Lower wholesale market
     prices decreased revenue received under ComEd's PPO by $71 million.

o    Weather.  The  weather  impact for the six months  ended June 30,  2003 was
     unfavorable  compared  to the same  period  in 2002 as a result  of  cooler
     spring weather in 2003. Cooling degree-days decreased 63% in the six months
     ended June 30, 2003 compared to the same period in 2002 and were  partially
     offset by a 13%  increase in heating  degree  days in the six months  ended
     June 30, 2003 compared to the same period in 2002.

o    Volume.  Revenues  from  higher  delivery  volume,  exclusive  of  weather,
     increased due to an increased  number of customers and increased  usage per
     customer, primarily residential and PPO.

     The $4 million increase in wholesale and miscellaneous  revenue for the six
months ended June 30, 2003 was comparable to the six months ended June 30, 2002.

Purchased Power

     Purchased  power expense  increased  $19 million,  or 2% for the six months
ended June 30,  2003.  The  increase in purchased  power  expense was  primarily
attributable to an increase of $22 million due to higher volume,  an increase of
$39 million due to pricing changes related to ComEd's PPA with Generation and an
increase of $31 million  under the PPA  related to  decommissioning  collections
associated with the adoption of SFAS No. 143 that were not included in purchased
power in 2002,  partially  offset by a $27 million  decrease due to  unfavorable
weather and a $49 million decrease as a result of customers choosing to purchase
energy from an ARES. The $31 million increase in purchased power expense related
to SFAS No. 143 is offset by lower regulatory asset amortization.

Operating and Maintenance

     O&M expense increased $26 million, or 6%, for the six months ended June 30,
2003. The increase in O&M expense was primarily  attributable  to a net one-time
charge of $41  million  in 2003 as the  result of the  Agreement  as more  fully
described in Note 4 of the Condensed  Combined Notes to  Consolidated  Financial
Statements  and an increase  of $6 million in the reserve for MGP  investigation
and  remediation  as a result  of  increased  costs  of a MGP site in Oak  Park,
Illinois,  partially  offset  by  higher  corporate  allocations  in 2002 due to
executive severance.




                                       98
<PAGE>

Depreciation and Amortization

     Depreciation and amortization  expense  decreased $78 million,  or 29%, for
the six months ended June 30, 2003 as follows:

<TABLE>
<CAPTION>
                                                      Six Months Ended June 30,
                                                      -------------------------
                                                         2003              2002         Variance          % Change
------------------------------------------------------------------------------------------------------------------
<S>                                                  <C>              <C>                 <C>              <C>
Depreciation expense                                 $    152         $     183           $  (31)          (16.9%)
Recoverable transition costs amortization                  23                43              (20)          (46.5%)
Other amortization expense                                 15                42              (27)          (64.3%)
-------------------------------------------------------------------------------------------------
Total depreciation and amortization                  $    190         $     268           $  (78)          (29.1%)
=================================================================================================
</TABLE>

     The decrease in depreciation expense is primarily due to lower depreciation
rates effective July 1, 2002,  partially  offset by higher  property,  plant and
equipment  balances.  ComEd completed a depreciation study and implemented lower
depreciation  rates effective July 1, 2002. The new  depreciation  rates reflect
ComEd's  significant  construction  program  in  recent  years,  changes  in and
development of new  technologies,  and changes in estimated  plant service lives
since the last depreciation study. The annual reduction in depreciation  expense
is estimated to be approximately $100 million ($60 million, net of income taxes)
based  on  December  31,  2001  plant  balances.  As a  result  of  the  change,
depreciation  expense  decreased $48 million ($29 million,  net of income taxes)
for the six months ended June 30, 2003.

     Recoverable transition costs amortization decreased in the six months ended
June 30, 2003  compared to the same period in 2002.  The decrease is a result of
the extension of the rate freeze through 2006 that occurred in June 2002.  ComEd
expects to fully  recover its  recoverable  transition  costs  regulatory  asset
balance of $153 million by 2006.  Consistent  with the provision of the Illinois
legislation, regulatory assets may be recovered at amounts that provide ComEd an
earned  return  on  common  equity  within  the  Illinois  legislation  earnings
threshold.

     The   decrease   in   other   amortization   primarily   relates   to   the
reclassification  of a regulatory asset for nuclear  decommissioning as a result
of the  adoption of SFAS No. 143 in 2003 (see Note 2 of the  Condensed  Combined
Notes  to  Consolidated  Financial  Statements).  This  decrease  is  offset  by
increased purchased power expense from Generation.

Taxes Other Than Income

     Taxes other than income were  comparable  for the six months ended June 30,
2003 and 2002,  primarily as a result of a $5 million refund in 2003 of Illinois
Electricity  Distribution  taxes offset by $6 million in Illinois Public Utility
Fund taxes that were not charged in 2002.

Interest Charges

     Interest  charges  consist  of  interest   expense  and   distributions  on
mandatorily  redeemable  preferred  securities.  Interest charges  decreased $37
million,  or 15%,  for the six  months  ended June 30,  2003.  The  decrease  in
interest  expense was  primarily  attributable  to the impact of lower  interest
rates as a result of  refinancing  existing debt at lower interest rates for the
six months ended June 30, 2003 as compared to the six months ended June 30, 2002
and the annual retirement of $340 million in Transitional Trust Notes.




                                       99
<PAGE>

Other, Net

     Other,  net  increased by $5 million for the six months ended June 30, 2003
as compared to the same period in 2002. The increase was primarily  attributable
to  the  reversal  of a $12  million  reserve  in  2003  for a  potential  plant
disallowance as the result of the Agreement as more fully described in Note 4 to
the Condensed Combined Notes to Consolidated Financial Statements.

Income Taxes

     The  effective  income tax rate was 39.9% for the six months ended June 30,
2003, compared to 39.6% for the six months ended June 30, 2002.

     Due to revenue needs in the states in which ComEd  operates,  various state
income tax and fee increases  have been proposed or are being  contemplated.  If
these changes are enacted, they could increase ComEd's state income tax expense.
At this time,  however,  ComEd cannot predict whether  legislation or regulation
will be introduced, the form of any legislation or regulation,  whether any such
legislation or regulation will be passed by the state legislatures or regulatory
bodies,  and, if enacted,  whether any such  legislation or regulation  would be
effective  retroactively or prospectively.  As a result,  ComEd cannot currently
estimate the effect of these potential changes in tax laws or regulation.

Cumulative Effect of a Change in Accounting Principle

     On January 1, 2003,  ComEd adopted SFAS No. 143,  resulting in income of $5
million, net of tax.

LIQUIDITY AND CAPITAL RESOURCES

     ComEd's  business is capital  intensive and requires  considerable  capital
resources.  ComEd's  capital  resources  are  primarily  provided by  internally
generated  cash flows from  operations  and, to the extent  necessary,  external
financing  including the issuance of commercial paper, or capital  contributions
from  Exelon.  ComEd's  access to  external  financing  at  reasonable  terms is
dependent on its credit ratings and general business conditions, as well as that
of the utility  industry in general.  If these  conditions  deteriorate to where
ComEd no longer has access to external  financing  sources at reasonable  terms,
ComEd has access to a revolving credit facility that ComEd currently utilizes to
support its commercial paper program. See the Credit Issues section of Liquidity
and  Capital  Resources  for  further  discussion.  Capital  resources  are used
primarily  to  fund  ComEd's  capital  requirements,   including   construction,
repayments of maturing debt and the payment of dividends.

     In the second quarter of 2003,  ComEd  progressed in its plans to implement
the new business  model referred to as The Exelon Way. The Exelon Way is focused
on  improving   operating  cash  flows  while  meeting   service  and  financial
commitments  through  improved  integration of operations and  consolidation  of
support  functions.  As part of the  implementation  of The  Exelon  Way,  ComEd
anticipates  incurring expenses  associated with the  rationalization of certain
business  functions  and  employee  separation  costs.  These  expenses  may  be
significant  and are expected to be incurred  during the remaining  half of 2003
through 2005. However, these costs cannot be reasonably estimated at this time.




                                      100
<PAGE>

Cash Flows from Operating Activities

     Cash flows  provided  by  operations  were $430  million for the six months
ended June 30, 2003  compared to $740  million for the six months ended June 30,
2002.  The decrease in cash flows in 2003 was primarily  attributable  to a $155
million  decrease in working  capital as a result of the paydown of intercompany
payables to  affiliates  and other  outstanding  liabilities,  a decrease of $87
million  for pension  and  non-pension  postretirement  benefits  obligation,  a
decrease in depreciation and amortization of $78 million  partially offset by an
increase  in net income of $41  million.  ComEd's  future cash flows will depend
upon the ability to achieve  cost  savings in  operations  and the impact of the
economy, weather, and customer choice on its revenues.  Although the amounts may
vary  from  period  to  period  as a result  of  uncertainties  inherent  in the
business,  ComEd  expects to continue to provide a reliable and steady source of
internal cash flow from operations for the foreseeable future.

Cash Flows from Investing Activities

     Cash flows  used in  investing  activities  were $506  million  for the six
months  ended June 30, 2003  compared to $352  million for the six months  ended
June 30, 2002.  The increase in cash flows used in investing  activities in 2003
was primarily  attributable  to the $165 million loaned to Generation as part of
the intercompany money pool.

     ComEd  estimates  that it will spend  approximately  $720  million in total
capital  expenditures  for 2003.  Approximately  two-thirds of the budgeted 2003
expenditures  are for continuing  efforts to further  improve the reliability of
its  transmission  and  distribution  systems.  The  remaining  one third is for
capital additions to support new business and customer growth. ComEd anticipates
that its capital  expenditures  will be funded by  internally  generated  funds,
borrowings,  the issuance of preferred securities, or capital contributions from
Exelon.  ComEd's proposed capital expenditures and other investments are subject
to periodic  review and revision to reflect  changes in economic  conditions and
other factors.

Cash Flows from Financing Activities

     Cash flows from  financing  activities  were $94 million for the six months
ended June 30, 2003 as compared to cash flows used in  financing  of $57 million
for the six months ended June 30,  2002.  Cash flows from  financing  activities
were primarily  attributable to debt issuances  partially  offset by retirements
and redemptions and payments of dividends to Exelon.  The increase in cash flows
from  financing  activities  is primarily  attributable  to  increased  debt and
preferred  securities  issuances of $634 million  partially  offset by increased
debt and preferred securities redemptions of $452 million and increased interest
rate  swap  settlement  payments  of $41  million.  See Note 9 of the  Condensed
Combined Notes to Consolidated  Financial  Statements for further  discussion of
ComEd's debt and preferred  securities financing  activities.  ComEd paid a $211
million dividend to Exelon during the six months ended June 30, 2003 compared to
a $235 million dividend for the six months ended June 30, 2002.




                                      101
<PAGE>

Credit Issues

     ComEd meets its short-term  liquidity  requirements  primarily  through the
issuance of commercial  paper and borrowings  from Exelon's  intercompany  money
pool.  ComEd,  along with Exelon,  PECO, and Generation,  participates in a $1.5
billion  unsecured  364-day revolving credit facility with a group of banks. The
credit  facility that became  effective on November 22, 2002 includes a term-out
option that allows any outstanding borrowings at the end of the revolving credit
period to be repaid on November  21,  2004.  Exelon may increase or decrease the
sublimits of each of the participants upon written notification to the banks. As
of June 30, 2003, ComEd's sublimit was $100 million. The credit facility is used
principally to support ComEd's commercial paper program. At June 30, 2003, ComEd
had no commercial paper outstanding. For the six months ended June 30, 2003, the
average interest rate on notes payable was approximately 1.47%.

     The credit  facility  requires ComEd to maintain a cash from  operations to
interest expense ratio for the twelve-month  period ended on the last day of any
quarter.  The ratio  excludes  revenues and interest  expenses  attributable  to
securitization of debt, certain changes in working capital, and distributions on
preferred securities of subsidiaries.  ComEd's threshold for the ratio reflected
in the  credit  agreement  cannot be less  than  2.25 to 1 for the  twelve-month
period ended June 30, 2003. At June 30, 2003,  ComEd was in compliance  with the
credit agreement thresholds.

     To provide an additional short-term borrowing option that will generally be
more  favorable  to  the  borrowing  participants  than  the  cost  of  external
financing,  Exelon operates an  intercompany  money pool.  Participation  in the
money pool is  subject  to  authorization  by the  Exelon  corporate  treasurer.
ComEd's  subsidiary,   Commonwealth  Edison  Company  of  Indiana,  Inc.,  PECO,
Generation  and BSC may  participate in the money pool as lenders and borrowers,
and Exelon Corporate and ComEd as lenders.  Funding of, and borrowings from, the
money pool are  predicated  on whether such funding  results in mutual  economic
benefits to each of the  participants,  although Exelon is not permitted to be a
net borrower from the money pool.  Interest on borrowings is based on short-term
market rates of interest,  or, if from an external  source,  specific  borrowing
rates.  There were no material money pool  transactions in 2002.  During the six
months  ended June 30, 2003,  ComEd had various  loans to  Generation  under the
money pool. The maximum amount of outstanding  loans at any time during 2003 was
$342 million.  As of June 30, 2003,  Generation owed ComEd $165 million on these
loans.  For the six  months  ended  June 30,  2003,  ComEd  earned $1 million in
interest.

     ComEd's  access to the capital  markets,  including  the  commercial  paper
market, and its financing costs in those markets are dependent on its securities
ratings.  None of ComEd's  borrowings  is subject to default or  prepayment as a
result of a downgrading of securities  ratings although such a downgrading could
increase interest charges under certain bank credit facilities.

     Under  PUHCA,  ComEd  can only  pay  dividends  from  retained  or  current
earnings.  However,  the SEC has  authorized  ComEd to pay up to $500 million in
dividends  out of  additional  paid-in  capital,  provided  ComEd  may  not  pay
dividends out of paid-in capital after December 31, 2002 if its common equity is
less than 30% of its total capitalization  (including




                                      102
<PAGE>

transitional trust notes). At June 30, 2003, ComEd had retained earnings of $767
million  and its common  equity  ratio was 46%.  Long-term  debt  included  $1.8
billion of transitional trust notes.

Contractual Obligations, Commercial Commitments and Off-Balance Sheet
Obligations

     Contractual  obligations  represent cash obligations that are considered to
be firm commitments and commercial  commitments  represent commitments triggered
by future events. ComEd's contractual  obligations and commercial commitments as
of June 30, 2003 were materially  unchanged,  other than in the normal course of
business,  from the  amounts  set  forth in the 2002 Form  10-K  except  for the
following:

o    On March 3, 2003,  ComEd entered into the Agreement  with various  Illinois
     electric  retail market  suppliers,  key customer  groups and  governmental
     parties  regarding  several  matters  affecting  ComEd's rates for electric
     service.  The Agreement  addressed,  among other things,  issues related to
     ComEd's delivery  services rate proceeding,  market value index proceeding,
     the process for competitive service  declarations for large-load  customers
     and an extension of the PPA with  Generation.  During the second quarter of
     2003, the ICC issued orders  consistent  with the  Agreement,  which is now
     effective.

          The Agreement  provides for a modification of the methodology  used to
     determine  ComEd's  market  value  energy  credit.  That  credit is used to
     determine  the price for  specified  market-based  rate  offerings  and the
     amount of the CTC that  ComEd is  allowed to  collect  from  customers  who
     select an ARES or the PPO. The credit was adjusted  upwards  through agreed
     upon  "adders"  which took  effect in June 2003 and will have the effect of
     reducing ComEd's CTC charges to customers.  Prior to the Agreement, all CTC
     charges were subject to annual  mid-year  adjustments  based on the forward
     market prices for on-peak energy and historical  market prices for off-peak
     energy. The Agreement provides that the annual market price adjustment will
     reflect  forward  market  prices for energy,  rather than  historical,  and
     allows  customers  an option to lock in current  levels of CTC  charges for
     multi-year periods during the regulatory  transition period ending in 2006.
     These changes provide  customers and suppliers  greater price certainty and
     are expected to result in an increase in the number of  customers  electing
     to purchase energy from alternate suppliers.

          The annual market price  adjustments to the CTC effective in June 2002
     and June 2003 had the effect of significantly  increasing the CTC charge in
     June 2002, and subsequently  significantly  reducing the CTC charge in June
     2003. In 2002,  ComEd  collected $306 million in CTC revenue.  Based on the
     changes  in the CTC as part of the  Agreement  and on  current  assumptions
     about the competitive  price of delivered  energy and customers'  choice of
     electric  supplier,  ComEd estimates that CTC revenue will be approximately
     $300 million in 2003 and  approximately  $140 million for each of the years
     2004 through 2006.

          In the first  quarter of 2003,  ComEd  recorded  a charge to  earnings
     associated   with  the  funding  of  specified   programs  and  initiatives
     associated  with the  Agreement  of $51  million on a present  value  basis
     before income taxes.  This amount is partially  offset by the reversal of a
     $12 million (before income taxes) reserve  established in the third quarter
     of 2002 for a potential  capital  disallowance in ComEd's delivery services
     rate  proceeding and a credit of




                                      103
<PAGE>

     $10 million (before income taxes) related to the capitalization of employee
     incentive  payments  provided for in the delivery  services order.  The net
     one-time charge for these items is $29 million (before income taxes).

o    ComEd has entered into several  agreements with a tax consultant related to
     the filing of refund claims with the IRS. The fees for these agreements are
     contingent upon a successful outcome and are based upon a percentage of the
     refunds  recovered from the IRS, if any. As such, ComEd would have positive
     net cash flows related to these  agreements if any fees are paid to the tax
     consultant.  These  potential  tax  benefits and  associated  fees could be
     material to the financial position, results of operations and cash flows of
     ComEd.  ComEd's  tax  benefits  for  periods  prior to the Merger  would be
     recorded as a  reduction  of goodwill  pursuant  to a  reallocation  of the
     Merger  purchase  price.  ComEd  cannot  predict  the  timing  of the final
     resolution of these refund claims.

o    See  Note 9 to the  Condensed  Combined  Notes  to  Consolidated  Financial
     Statements for discussion of material changes in ComEd's debt and preferred
     securities obligations from those set forth in the 2002 Form 10-K.

o    See  Note 8 of the  Condensed  Combined  Notes  to  Consolidated  Financial
     Statements  for  commercial   commitments   tables   representing   ComEd's
     commitments not recorded on the balance sheet but potentially  triggered by
     future  events,  including  obligations  to make payment on behalf of other
     parties and financing arrangements to secure their obligations.








                                      104
<PAGE>

PECO ENERGY COMPANY
-------------------

GENERAL

     PECO operates in a single business segment,  and its operations  consist of
the  regulated  sale  of  electricity  and   distribution  and  transmission  in
southeastern  Pennsylvania and the sale of natural gas and distribution services
in the Pennsylvania counties surrounding the City of Philadelphia.

RESULTS OF OPERATIONS

Three Months Ended June 30, 2003 Compared to Three Months Ended June 30, 2002

Significant Operating Trends - PECO

<TABLE>
<CAPTION>
                                                              Three Months Ended June 30,
                                                              ---------------------------
                                                                       2003         2002     Variance     % Change
-------------------------------------------------------------------------------------------------------------------
<S>                                                               <C>            <C>          <C>           <C>
OPERATING REVENUES                                                $     961      $   995      $   (34)      (3.4%)

OPERATING EXPENSES
    Purchased power                                                     386          405          (19)      (4.7%)
    Fuel                                                                 67           53           14       26.4%
    Operating and maintenance                                           121          131          (10)      (7.6%)
    Depreciation and amortization                                       116          109            7        6.4%
    Taxes other than income                                              47           63          (16)     (25.4%)
------------------------------------------------------------------------------------------------------
         Total operating expenses                                       737          761          (24)      (3.2%)
------------------------------------------------------------------------------------------------------

OPERATING INCOME                                                        224          234          (10)      (4.3%)
------------------------------------------------------------------------------------------------------

OTHER INCOME AND DEDUCTIONS
    Interest expense                                                    (83)         (92)           9       (9.8%)
    Distributions on mandatorily redeemable preferred securities         (2)          (2)          --       --
    Other, net                                                            1            2           (1)     (50.0%)
------------------------------------------------------------------------------------------------------
         Total other income and deductions                              (84)         (92)           8       (8.7%)
------------------------------------------------------------------------------------------------------

INCOME BEFORE INCOME TAXES                                              140          142           (2)      (1.4%)

INCOME TAXES                                                             52           49            3        6.1%
------------------------------------------------------------------------------------------------------

NET INCOME                                                               88           93           (5)      (5.4%)
Preferred stock dividends                                                (2)          (2)          --       --
------------------------------------------------------------------------------------------------------

NET INCOME ON COMMON STOCK                                        $      86      $    91         $ (5)      (5.5%)
======================================================================================================
</TABLE>




                                      105
<PAGE>

Net Income

     Net income on common stock decreased $5 million, or 6% for the three months
ended June 30, 2003 as compared to the same period in 2002.  The  decrease was a
result of lower  sales  volume and  unfavorable  weather  conditions,  partially
offset by lower operating and maintenance expenses,  taxes other than income and
interest expense on debt.

Operating Revenue

PECO's electric sales statistics are as follows:

<TABLE>
<CAPTION>
                                                    Three Months Ended June 30,
                                                    ---------------------------
Retail Deliveries - (in GWhs)                            2003              2002         Variance         % Change
------------------------------------------------------------------------------------------------------------------
<S>                                                     <C>               <C>                <C>            <C>
Bundled Deliveries (1)
Residential                                             2,274             2,115              159            7.5%
Small Commercial & Industrial                           1,532             1,881             (349)         (18.6%)
Large Commercial & Industrial                           3,695             3,927             (232)          (5.9%)
Public Authorities & Electric Railroads                   222               200               22           11.0%
------------------------------------------------------------------------------------------------
                                                        7,723             8,123             (400)          (4.9%)
------------------------------------------------------------------------------------------------
Unbundled Deliveries (2)
Residential                                               186               557             (371)         (66.6%)
Small Commercial & Industrial                             323                 2              321              n.m.
Large Commercial & Industrial                             192                13              179              n.m.
Public Authorities & Electric Railroads (3)                --                --               --           --
------------------------------------------------------------------------------------------------
                                                          701               572              129           22.6%
------------------------------------------------------------------------------------------------
Total Retail Deliveries                                 8,424             8,695             (271)          (3.1%)
================================================================================================
<FN>
(1)  Bundled service  reflects  deliveries to customers  taking electric service
     under tariffed rates.
(2)  Unbundled   service  reflects   customers   electing  to  receive  electric
     generation service from an alternative energy supplier.
(3)  PECO's  unbundled sales to Public  Authorities and Electric  Railroads were
     less than one GWh per quarter.

n.m. - not meaningful
</FN>
</TABLE>

<TABLE>
<CAPTION>
                                                    Three Months Ended June 30,
                                                    ---------------------------
Electric Revenue                                         2003              2002         Variance         % Change
------------------------------------------------------------------------------------------------------------------
<S>                                                  <C>              <C>               <C>                 <C>
Bundled Revenue (1)
Residential                                          $    297         $     278         $     19            6.8%
Small Commercial & Industrial                             180               224              (44)         (19.6%)
Large Commercial & Industrial                             267               288              (21)          (7.3%)
Public Authorities & Electric Railroads                    21                19                2           10.5%
-------------------------------------------------------------------------------------------------
                                                          765               809              (44)          (5.4%)
-------------------------------------------------------------------------------------------------
Unbundled Revenue (2)
Residential                                                14                42              (28)         (66.7%)
Small Commercial & Industrial                              17                --               17          100.0%
Large Commercial & Industrial                               5                 1                4         n.m.
Public Authorities & Electric Railroads (3)                --                --               --              --
-------------------------------------------------------------------------------------------------
                                                           36                43               (7)         (16.3%)
-------------------------------------------------------------------------------------------------
Total Electric Retail Revenues                            801               852              (51)          (6.0%)
Wholesale and Miscellaneous Revenue (4)                    50                59               (9)         (15.3%)
-------------------------------------------------------------------------------------------------
Total Electric Revenue                               $    851         $     911         $    (60)          (6.6%)
=================================================================================================
<FN>
(1)  Bundled revenue  reflects  revenue from customers  taking electric  service
     under tariffed rates,  which includes the cost of energy, the delivery cost
     of the transmission and the distribution of the energy and a CTC charge.




                                      106
<PAGE>

(2)  Unbundled  revenue  reflects  revenue  from  customers  electing to receive
     generation  from an  alternative  supplier,  which  includes a distribution
     charge and a CTC charge.
(3)  PECO's  unbundled sales to Public  Authorities and Electric  Railroads were
     less than $1 million per quarter.
(4)  Wholesale and miscellaneous revenues include transmission revenue and other
     wholesale energy sales.
</FN>
</TABLE>

     The changes in electric retail revenues for the three months ended June 30,
2003, as compared to the same period in 2002, are as follows:

<TABLE>
<CAPTION>
                                                                                                          Variance
-------------------------------------------------------------------------------------------------------------------
<S>                                                                                                          <C>
Weather                                                                                                      $ (21)
Customer choice                                                                                                 (8)
Volume                                                                                                          (7)
Other effects                                                                                                  (15)
-------------------------------------------------------------------------------------------------------------------
Retail revenue                                                                                               $ (51)
===================================================================================================================
</TABLE>

o    Weather. The demand for electricity is impacted by weather conditions. Very
     warm  weather in summer  months and very cold  weather in other  months are
     referred  to  as  "favorable  weather  conditions"  because  these  weather
     conditions  result in  increased  sales of  electricity.  Conversely,  mild
     weather reduces demand. The weather impact was unfavorable  compared to the
     prior year as a result of cooler spring weather during the quarter. Cooling
     degree-days  decreased  40% and heating  degree-days  increased 38% for the
     three months ended June 30, 2003 compared to the same period in 2002.
o    Customer  Choice.  All PECO  customers  may choose to purchase  energy from
     other suppliers. This choice generally does not impact kWh deliveries,  but
     reduces  revenue  collected from  customers  because they are not obtaining
     generation supply from PECO.

          For the three  months  ended June 30,  2003,  the energy  provided  by
     alternative  suppliers was 701 GWhs or 8.3% as compared to 572 GWhs or 6.6%
     for the three months ended June 30, 2002.  As of June 30, 2003,  the number
     of  customers  served by  alternative  suppliers  was  310,821  or 20.3% as
     compared to 308,866 or 20.2% as of June 30,  2002.  The  decrease in retail
     deliveries  is  primarily a result of customers  selecting  an  alternative
     electric generation supplier.

          The PUC's Final Electric  Restructuring Order established market share
     thresholds (MST) to promote competition.  The MST requirements provide that
     if, as of January  1, 2003,  less than 50% of  residential  and  commercial
     customers  have chosen an alternative  electric  generation  supplier,  the
     number of customers  sufficient to meet the MST shall be randomly  selected
     and assigned to an alternative  electric  generation supplier through a PUC
     determined process. On January 1, 2003, the number of customers choosing an
     alternative  electric  generation supplier did not meet the MST. In January
     2003,  PECO  submitted  to the PUC an MST  plan to meet  the 50%  threshold
     requirement for its commercial customers,  which was approved by the PUC in
     February  2003. As of March 31, 2003, an auction had been completed for the
     commercial  customers.  In May  2003,  the  customer  enrollment  phase was
     completed and customers  that did not choose to opt out of the program were
     transferred to the alternative electric generation  suppliers.  In February
     2003,  PECO filed a residential  customer MST plan, and on May 1, 2003, the
     PUC approved the plan.  The approved plan  provides for a two-step  process
     with a total of up to  400,000  residential  customers  being  assigned  to
     winning alternative  electric generation supplier bidders: up to 100,000 in
     July 2003, and another  300,000 in December 2003. The auction for the first
     phase of the  residential  program  received no supplier  bids.  Therefore,
     according to the MST plan




                                      107
<PAGE>


     requirements,  75% of  those  customers  are  required  to be  added to the
     auction  for the second  phase of the  residential  program  for a total of
     375,000  customers.  The  auction for the second  phase of the  residential
     customer  MST  plan is  scheduled  for  September  2003  and  the  selected
     customers  would be  transferred  effective  December  2003.  Any  customer
     transferred  would have the right to return to PECO at any time.  PECO does
     not expect the  transfer  of  customers  pursuant to the MST plan to have a
     material  impact on its results of operations,  financial  position or cash
     flows.
o    Volume. Exclusive of weather impacts, lower delivery volume affected PECO's
     revenue by $7 million compared to the same period in 2002 primarily related
     to  decreases  in  usage  by  the  residential  and  large  commercial  and
     industrial customer classes partially offset by an increase in usage by the
     small commercial and industrial class.
o    Other Effects.  The decrease in revenues from other effects is attributable
     to a  decrease  of $15  million  in the  average  price mix  related to all
     customer classes as compared to the same period in 2002.

              PECO's gas sales  statistics  for the three  months ended June 30,
     2003 as compared to the same period in 2002 are as follows:

<TABLE>
<CAPTION>
                                                                  Three Months Ended June 30,
                                                                  ---------------------------
                                                                            2003         2002     Variance     % Change
------------------------------------------------------------------------------------------------------------------------
<S>                                                                       <C>          <C>             <C>        <C>
     Deliveries in mmcf                                                   15,001       14,286          715        5.0%
     Revenue                                                           $     110    $      84        $  26       31.0%
------------------------------------------------------------------------------------------------------------
</TABLE>

     The changes in gas revenue for the three  months  ended June 30,  2003,  as
compared to the same period in 2002, are as follows:

<TABLE>
<CAPTION>
                                                                                                               Variance
-----------------------------------------------------------------------------------------------------------------------
<S>                                                                                                            <C>
Weather                                                                                                        $     14
Rate changes                                                                                                         10
Volume                                                                                                                2
-----------------------------------------------------------------------------------------------------------------------
Gas revenue                                                                                                    $     26
=======================================================================================================================
</TABLE>

o    Weather.  The demand for gas is impacted by weather  conditions.  Very cold
     weather  in  non-summer  months  is  referred  to  as  "favorable   weather
     conditions,"  because these weather conditions result in increased sales of
     gas.  Conversely,  mild  weather  reduces  demand.  The weather  impact was
     favorable  compared to the prior year as a result of cooler spring  weather
     during the quarter.  Heating degree-days  increased 38% in the three months
     ended June 30, 2003 compared to the same period in 2002.
o    Rate Changes.  The favorable  variance in rate changes is attributable to a
     15% increase and a 7% increase in the purchased  gas  adjustment by the PUC
     effective  March 1, 2003 and June 1, 2003,  respectively.  The average rate
     per  million  cubic feet for the three  months  ended June 30, 2003 was 22%
     higher  than the same  period in 2002.  PECO's  gas rates  are  subject  to
     periodic  adjustments by the PUC and are designed to recover from or refund
     to customers  the  difference  between the actual cost of purchased gas and
     the amount  included  in base rates and to recover or refund  increases  or
     decreases in certain state taxes not recovered in base rates.



                                      108
<PAGE>

o    Volume. Exclusive of weather impacts, delivery volume was consistent in the
     three months  ended June 30, 2003  compared to the same period in 2002 with
     increased retail sales,  partially offset by lower transportation  volumes.
     Deliveries  to  customers,  excluding  transportation  and the  effects  of
     weather,  increased 4% in the three months ended June 30, 2003  compared to
     the same period in 2002.

Purchased Power

     Purchased  power expense for the three months ended June 30, 2003 decreased
$19  million,  or 5%, as compared to the same  period in 2002.  The  decrease in
purchased power expense was primarily attributable to $12 million as a result of
unfavorable  weather  conditions,  $7  million  related  to lower PJM  ancillary
charges and $5 million from customers in  Pennsylvania  selecting an alternative
electric generation supplier.

     Fuel Fuel expense for the three months  ended June 30, 2003  increased  $14
million,  or 26%,  as compared to the same  period in 2002.  This  increase  was
primarily  attributable to $11 million attributable to higher gas prices and $10
million  as a result of  favorable  weather  conditions  partially  offset by $8
million related to lower wholesale sales of gas.

Operating and Maintenance

     O&M expense for the three months ended June 30, 2003 decreased $10 million,
or 8%, as compared to the same period in 2002.  The  decrease in O&M expense was
primarily  attributable  to $7 million of lower expense related to the allowance
for the  uncollectible  accounts,  $7 million of lower costs associated with the
initial implementation of automated meter reading services,  partially offset by
$2 million related to higher corporate  allocations and $2 million of additional
severance costs.

Depreciation and Amortization

     Depreciation and  amortization  expense for the three months ended June 30,
2003  increased  $7  million,  or 6%, as  compared to the same period in 2002 as
follows:

<TABLE>
<CAPTION>
                                                    Three Months Ended June 30,
                                                    ---------------------------
                                                         2003              2002         Variance          % Change
-------------------------------------------------------------------------------------------------------------------
<S>                                                    <C>            <C>                 <C>                 <C>
Competitive transition charge amortization             $   79         $      72           $    7              9.7%
Depreciation expense                                       33                32                1              3.1%
Other amortization expense                                  4                 5               (1)           (20.0%)
--------------------------------------------------------------------------------------------------
Total depreciation and amortization                    $  116         $     109           $    7              6.4%
==================================================================================================
</TABLE>

     The  additional  amortization  of the  CTC  is in  accordance  with  PECO's
original settlement under the Pennsylvania Competition Act.

Taxes Other Than Income

     Taxes other than income for the three months ended June 30, 2003  decreased
$16  million,  or 25%, as compared to the same period in 2002.  The decrease was
primarily  attributable  to $12  million  related to the  reversal  of a use tax
accrual  resulting  from an audit  settlement  and $2  million  of  lower  gross
receipts tax related to lower revenues.




                                      109
<PAGE>

Interest Charges

     Interest  charges  consist  of  interest   expense  and   distributions  on
mandatorily  redeemable  preferred  securities.  Interest  charges  decreased $9
million, or 10%, in the three months ended June 30, 2003 as compared to the same
period in 2002.  The  decrease  was  primarily  attributable  to lower  interest
expense  on  long-term  debt of $9 million  as a result of  scheduled  principal
payments and refinancing of existing debt at lower interest rates.

Other, Net

     Other,  net  decreased  income by $1 million in the three months ended June
30, 2003 as compared to the same period in 2002.  The decrease was  attributable
to lower interest income of $1 million.

Income Taxes

     The  effective  tax rate was 37.1% for the three months ended June 30, 2003
as compared to 34.5% for the same period in 2002.  The increase in the effective
tax rate primarily reflects the impact of changes in income before income taxes.

Preferred Stock Dividends

     Preferred  stock  dividends  for the three  months ended June 30, 2003 were
consistent as compared to the same period in 2002.




                                      110
<PAGE>

Six Months Ended June 30, 2003 Compared to Six Months Ended June 30, 2002

     Significant Operating Trends - PECO

<TABLE>
<CAPTION>
                                                               Six Months Ended June 30,
                                                               -------------------------
                                                                       2003         2002     Variance     % Change
------------------------------------------------------------------------------------------------------------------
<S>                                                               <C>            <C>          <C>            <C>
OPERATING REVENUES                                                $   2,178      $ 2,015      $   163        8.1%

OPERATING EXPENSES
    Purchased power                                                     808          756           52        6.9%
    Fuel                                                                257          188           69       36.7%
    Operating and maintenance                                           261          267           (6)      (2.2%)
    Depreciation and amortization                                       236          221           15        6.8%
    Taxes other than income                                             110          122          (12)      (9.8%)
-------------------------------------------------------------------------------------------------------
         Total operating expenses                                     1,672        1,554          118        7.6%
-------------------------------------------------------------------------------------------------------

OPERATING INCOME                                                        506          461           45        9.8%
-------------------------------------------------------------------------------------------------------

OTHER INCOME AND DEDUCTIONS
    Interest expense                                                   (168)        (187)          19      (10.2%)
    Distributions on mandatorily redeemable preferred securities         (5)          (5)          --       --
    Other, net                                                           10            2            8         n.m.
-------------------------------------------------------------------------------------------------------
         Total other income and deductions                             (163)        (190)          27      (14.2%)
-------------------------------------------------------------------------------------------------------

INCOME BEFORE INCOME TAXES                                              343          271           72       26.6%

INCOME TAXES                                                            119           90           29       32.2%
-------------------------------------------------------------------------------------------------------

NET INCOME                                                              224          181           43       23.8%
Preferred stock dividends                                                (3)          (4)           1      (25.0%)
-------------------------------------------------------------------------------------------------------

NET INCOME ON COMMON STOCK                                        $     221      $   177         $ 44       24.9%
=======================================================================================================
<FN>
n.m. - not meaningful
</FN>
</TABLE>

Net Income

     Net income on common stock increased $44 million, or 25% for the six months
ended June 30, 2003 as compared to the same period in 2002.  The  increase was a
result of higher sales volume,  favorable weather  conditions and lower interest
expense on debt, partially offset by increased income taxes and depreciation and
amortization expense.




                                      111
<PAGE>

Operating Revenue

     PECO's electric sales statistics are as follows:

<TABLE>
<CAPTION>
                                                      Six Months Ended June 30,
                                                      -------------------------
Retail Deliveries  (in GWhs)                             2003              2002         Variance         % Change
------------------------------------------------------------------------------------------------------------------
<S>                                                     <C>               <C>              <C>              <C>
Bundled Deliveries (1)
Residential                                             5,389             4,171            1,218           29.2%
Small Commercial & Industrial                           3,312             3,638             (326)          (9.0%)
Large Commercial & Industrial                           7,177             7,278             (101)          (1.4%)
Public Authorities & Electric Railroads                   475               393               82           20.9%
-------------------------------------------------------------------------------------------------
                                                       16,353            15,480              873            5.6%
-------------------------------------------------------------------------------------------------
Unbundled Deliveries (2)
Residential                                               450             1,348             (898)         (66.6%)
Small Commercial & Industrial                             525                99              426            n.m.
Large Commercial & Industrial                             402               116              286            n.m.
Public Authorities & Electric Railroads (3)                --                --               --             --
-------------------------------------------------------------------------------------------------
                                                        1,377             1,563             (186)         (11.9%)
-------------------------------------------------------------------------------------------------
Total Retail Deliveries                                17,730            17,043              687            4.0%
=================================================================================================
<FN>
(1)  Bundled service  reflects  deliveries to customers  taking electric service
     under tariffed rates.
(2)  Unbundled   service  reflects   customers   electing  to  receive  electric
     generation service from an alternative energy supplier.
(3)  PECO's  unbundled sales to Public  Authorities and Electric  Railroads were
     less than one GWh per quarter.

     n.m. - not meaningful
</FN>
</TABLE>

<TABLE>
<CAPTION>
                                                      Six Months Ended June 30,
                                                      -------------------------
Electric Revenue                                         2003              2002         Variance         % Change
-------------------------------------------------------------------------------------------------------------------
<S>                                                  <C>              <C>               <C>                <C>
Bundled Revenue (1)
Residential                                          $    656         $     522         $    134           25.7%
Small Commercial & Industrial                             374               413              (39)          (9.4%)
Large Commercial & Industrial                             534               532                2            0.4%
Public Authorities & Electric Railroads                    42                37                5           13.5%
--------------------------------------------------------------------------------------------------
                                                        1,606             1,504              102            6.8%
--------------------------------------------------------------------------------------------------
Unbundled Revenue (2)
Residential                                                31                96              (65)         (67.7%)
Small Commercial & Industrial                              27                 5               22            n.m.
Large Commercial & Industrial                              11                 3                8            n.m.
Public Authorities & Electric Railroads (3)                --                --               --              --
--------------------------------------------------------------------------------------------------
                                                           69               104              (35)         (33.7%)
--------------------------------------------------------------------------------------------------
Total Electric Retail Revenues                          1,675             1,608               67            4.2%
Wholesale and Miscellaneous Revenue (4)                   104               114              (10)          (8.8%)
--------------------------------------------------------------------------------------------------
Total Electric Revenue                               $  1,779         $   1,722           $   57            3.3%
==================================================================================================
<FN>
(1)  Bundled revenue  reflects  revenue from customers  taking electric  service
     under tariffed rates,  which includes the cost of energy, the delivery cost
     of the transmission and the distribution of the energy and a CTC charge.
(2)  Unbundled  revenue  reflects  revenue  from  customers  electing to receive
     generation  from an  alternative  supplier,  which  includes a distribution
     charge and a CTC charge.
(3)  PECO's  unbundled sales to Public  Authorities and Electric  Railroads were
     less than $1 million per quarter.
(4)  Wholesale and miscellaneous revenues include transmission revenue and other
     wholesale energy sales.
</FN>
</TABLE>




                                      112
<PAGE>

     The changes in electric  retail  revenues for the six months ended June 30,
2003, as compared to the same period in 2002, are as follows:

<TABLE>
<CAPTION>
                                                                                                               Variance
------------------------------------------------------------------------------------------------------------------------
<S>                                                                                                            <C>
Volume                                                                                                         $     36
Weather                                                                                                              26
Customer choice                                                                                                      11
Other effects                                                                                                        (6)
------------------------------------------------------------------------------------------------------------------------
Retail revenue                                                                                                 $     67
========================================================================================================================
</TABLE>

o    Volume.  Exclusive of weather  impacts,  higher  delivery  volume  affected
     PECO's revenue by $36 million compared to the same period in 2002 primarily
     related  to  increases  in the small and large  commercial  and  industrial
     customer classes.
o    Weather.  The weather impact was favorable  compared to the prior year as a
     result of colder winter weather  partially offset by cooler spring weather.
     Heating degree-days increased 34% and cooling degree-days decreased 40% for
     the six months ended June 30, 2003 compared to the same period in 2002.
o    Customer  Choice.  All PECO  customers  may choose to purchase  energy from
     other suppliers. This choice generally does not impact kWh deliveries,  but
     reduces  revenue  collected from  customers  because they are not obtaining
     generation supply from PECO.
          For the six  months  ended  June 30,  2003,  the  energy  provided  by
     alternative  suppliers  was 1,377 GWhs or 7.8% as compared to 1,563 GWhs or
     9.2% for the six  months  ended June 30,  2002.  As of June 30,  2003,  the
     number of customers served by alternative suppliers was 310,821 or 20.3% as
     compared to 308,866 or 20.2% as of June 30,  2002.  The  increase in retail
     deliveries  is  primarily a result of  customers  selecting or returning to
     PECO as their electric generation supplier.
o    Other Effects.  The decrease in revenues from other effects is attributable
     to a  decrease  of $6  million  in the  average  price mix  related  to all
     customer classes as compared to the same period in 2002.




                                      113
<PAGE>

     PECO's  gas sales  statistics  for the six months  ended  June 30,  2003 as
compared to the same period in 2002 are as follows:

<TABLE>
<CAPTION>
                                                               Six Months Ended June 30,
                                                               -------------------------
                                                                       2003         2002     Variance     % Change
-------------------------------------------------------------------------------------------------------------------
<S>                                                               <C>          <C>           <C>         <C>
Deliveries in mmcf                                                   54,627       45,643        8,984       19.7%
Revenue                                                           $     399    $     293       $  106       36.2%
-------------------------------------------------------------------------------------------------------
</TABLE>

     The  changes in gas  revenue  for the six months  ended June 30,  2003,  as
compared to the same period in 2002, are as follows:

<TABLE>
<CAPTION>
                                                                                                         Variance
------------------------------------------------------------------------------------------------------------------
<S>                                                                                                      <C>
Weather                                                                                                  $     73
Volume                                                                                                         17
Rate changes                                                                                                   13
Other                                                                                                           3
------------------------------------------------------------------------------------------------------------------
Gas revenue                                                                                              $     106
==================================================================================================================
</TABLE>

o    Weather.  The weather impact was favorable  compared to the prior year as a
     result of colder winter weather.  Heating degree-days  increased 34% in the
     six months ended June 30, 2003 compared to the same period in 2002.
o    Volume.  Exclusive of weather  impacts,  higher delivery  volume  increased
     revenue in the six months  ended June 30, 2003  compared to the same period
     in 2002  resulting from increased  retail sales  partially  offset by lower
     transportation volumes.  Deliveries to customers,  excluding transportation
     and the effects of weather,  increased  6% in the six months ended June 30,
     2003 compared to the same period in 2002.
o    Rate Changes.  The  favorable  variance in rates is  attributable  to a 15%
     increase  and a 7%  increase in the  purchased  gas  adjustment  by the PUC
     effective  March 1, 2003 and June 1, 2003,  respectively.  The average rate
     per  million  cubic  feet for the six months  ended  June 30,  2003 was 13%
     higher than the rate in the same 2002 period.  PECO's gas rates are subject
     to periodic  adjustments  by the PUC and are  designed  to recover  from or
     refund to customers the difference between actual cost of purchased gas and
     the amount  included  in base rates and to recover or refund  increases  or
     decreases in certain state taxes not recovered in base rates.


Purchased Power

     Purchased  power  expense for the six months ended June 30, 2003  increased
$52  million,  or 7%, as compared to the same  period in 2002.  The  increase in
purchased power expense was primarily attributable to $21 million as a result of
higher  electric  delivery  volume,  $11 million from customers in  Pennsylvania
selecting  or  returning  to PECO as their  electric  generation  supplier,  $10
million as a result of favorable  weather  conditions and $10 million related to
higher PJM ancillary charges.




                                      114
<PAGE>

Fuel

     Fuel expense for the six months ended June 30, 2003  increased $69 million,
or 40%,  as compared to the same period in 2002.  This  increase  was  primarily
attributable  to $50 million as a result of favorable  weather  conditions,  $14
million from higher gas prices and $8 million  attributable  to higher  delivery
volumes.

Operating and Maintenance

     O&M expense for the six months ended June 30, 2003 decreased $6 million, or
2%, as  compared  to the same  period in 2002.  The  decrease in O&M expense was
primarily attributable to $13 million of lower costs associated with the initial
implementation of automated meter reading services,  $9 million of lower expense
related to the allowance for  uncollectible  accounts and $5 million  related to
lower  corporate  allocations  partially  offset  by $3  million  of  additional
employee  benefits  costs,  $4 million of  incremental  storm costs in 2003,  $2
million of additional severance costs and $5 million of additional miscellaneous
other net positive impacts.

Depreciation and Amortization

     Depreciation  and  amortization  expense for the six months  ended June 30,
2003  increased  $15  million,  or 7%, as compared to the same period in 2002 as
follows:

<TABLE>
<CAPTION>
                                                      Six Months Ended June 30,
                                                      -------------------------
                                                         2003              2002         Variance          % Change
------------------------------------------------------------------------------------------------------------------
<S>                                                    <C>            <C>                <C>                 <C>
Competitive transition charge amortization             $  161         $     146          $    15             10.3%
Depreciation expense                                       66                63                3              4.8%
Other amortization expense                                  9                12               (3)           (25.0%)
--------------------------------------------------------------------------------------------------
Total depreciation and amortization                    $  236         $     221          $    15              6.8%
==================================================================================================
</TABLE>

     The  additional  amortization  of the  CTC  is in  accordance  with  PECO's
original  settlement under the Pennsylvania  Competition Act and the increase in
depreciation expense resulted from additional plant in service.

Taxes Other Than Income

     Taxes  other than income for the six months  ended June 30, 2003  decreased
$12  million,  or 10%, as compared to the same period in 2002.  The decrease was
primarily  attributable  to $12 million  related to the  reversal of the use tax
accrual  resulting from an audit  settlement  and a $3 million  decrease in real
estate taxes  partially  offset by $5 million of additional  gross  receipts tax
related to additional revenues.

Interest Charges

     Interest  charges  consist  of  interest   expense  and   distributions  on
mandatorily  redeemable  preferred  securities.  Interest charges  decreased $19
million,  or 10%, in the six months  ended June 30, 2003 as compared to the same
period in 2002.  The  decrease  was  primarily  attributable  to lower  interest
expense on  long-term  debt of $19  million as a result of  scheduled  principal
payments and refinancing of existing debt at lower interest rates.


                                      115
<PAGE>

Other, Net

     Other, net increased by $8 million in the six months ended June 30, 2003 as
compared to the same period in 2002. The increase was primarily  attributable to
higher interest income of $4 million and the favorable  settlement of a customer
contract of $3 million.

Income Taxes

     The  effective tax rate was 34.6% for the six months ended June 30, 2003 as
compared to 33.2% for the same period in 2002. The increase in the effective tax
rate primarily reflects the impact of changes in income before income taxes.

     Due to revenue  needs in the states in which PECO  operates,  various state
income tax and fee increases  have been proposed or are being  contemplated.  If
these changes are enacted,  they could increase PECO's state income tax expense.
At this time,  however,  PECO cannot predict  whether  legislation or regulation
will be introduced, the form of any legislation or regulation,  whether any such
legislation or regulation will be passed by the state legislatures or regulatory
bodies,  and, if enacted,  whether any such  legislation or regulation  would be
effective  retroactively or  prospectively.  As a result,  PECO cannot currently
estimate the effect of these potential changes in tax laws or regulation.

Preferred Stock Dividends

     Preferred  stock  dividends  for the six months  ended  June 30,  2003 were
consistent as compared to the same period in 2002.


LIQUIDITY AND CAPITAL RESOURCES

     PECO's  business is capital  intensive  and requires  considerable  capital
resources.  PECO's  capital  resources  are  primarily  provided  by  internally
generated  cash flows from  operations  and, to the extent  necessary,  external
financing  including the issuance of commercial  paper or capital  contributions
from  Exelon.  PECO's  access  to  external  financing  at  reasonable  terms is
dependent on its credit ratings and general business conditions, as well as that
of the utility  industry in general.  If these  conditions  deteriorate to where
PECO no longer has access to external  financing  sources at  reasonable  terms,
PECO has access to a revolving  credit facility that PECO currently  utilizes to
support its commercial paper program. See the Credit Issues section of Liquidity
and  Capital  Resources  for  further  discussion.  Capital  resources  are used
primarily  to  fund  PECO's  capital   requirements,   including   construction,
repayments of maturing debt and payment of dividends.

     In the second  quarter of 2003,  PECO  progressed in its plans to implement
the new business  model referred to as The Exelon Way. The Exelon Way is focused
on  improving   operating  cash  flows  while  meeting   service  and  financial
commitments  through  improved  integration of operations and  consolidation  of
support  functions.  As part  of the  implementation  of The  Exelon  Way,  PECO
anticipates  incurring expenses  associated with the  rationalization of certain
business  functions  and  employee  separation  costs.  These  expenses  may  be
significant  and are expected to be incurred  during the remaining  half of 2003
through 2005. However, these




                                      116
<PAGE>

costs cannot be reasonably estimated at this time.

Cash Flows from Operating Activities

     Cash flows  provided by  operations  for the six months ended June 30, 2003
and 2002 were $425 million and $468 million,  respectively. The decrease in cash
flows was  primarily  attributable  to a $73 million  change in deferred  energy
costs and a $4 million  decrease in working  capital,  partially offset by a $43
million  increase in net  income.  PECO's  cash flow from  operating  activities
primarily results from sales of electricity and gas to a stable and diverse base
of retail  customers at fixed prices.  PECO's future cash flows will depend upon
the ability to achieve  operating cost reductions and the impact of the economy,
weather and customer choice on its revenues.  Although the amounts may vary from
period to period as a result of the uncertainties inherent in its business, PECO
expects  that it will  continue  to  provide a  reliable  and  steady  source of
internal cash flow from operations for the foreseeable future.

Cash Flows from Investing Activities

     Cash flows used in investing  activities  for the six months ended June 30,
2003 and 2002 were $126 million and $122 million,  respectively. The increase in
cash  flows  used in  investing  activities  was  primarily  attributable  to an
increase in other investing activities.

     PECO's   projected   capital   expenditures  for  2003  are  $265  million.
Approximately  60% of the budgeted 2003  expenditures are for capital  additions
and upgrades to existing  facilities and the remainder are for capital additions
to support customer load growth. PECO anticipates that its capital  expenditures
will be funded by  internally  generated  funds,  borrowings,  the  issuance  of
preferred  securities,  or capital  contributions  from Exelon.  PECO's proposed
capital  expenditures  and other  investments are subject to periodic review and
revision to reflect changes in economic conditions and other factors.

Cash Flows from Financing Activities

     Cash flows used in financing  activities  for the six months ended June 30,
2003 and 2002 were $301 million and $306 million, respectively.  Cash flows used
in financing  activities are primarily  attributable to debt service and payment
of dividends to Exelon. The decrease in cash flows used in financing  activities
is primarily  attributable  to  additional  issuances of long-term  debt of $550
million, partially offset by increased debt and preferred securities redemptions
of $485 million.  See Note 9 of the  Condensed  Combined  Notes to  Consolidated
Financial Statements for further discussion of PECO's debt financing activities.
For the six months ended June 30, 2003,  PECO paid Exelon $165 million in common
stock dividends compared to $170 million for the same period in 2002.




                                      117
<PAGE>

Credit Issues

     PECO meets its  short-term  liquidity  requirements  primarily  through the
issuance of commercial  paper and borrowings  from Exelon's  intercompany  money
pool.  PECO,  along with Exelon,  ComEd and  Generation,  participates in a $1.5
billion  unsecured  364-day revolving credit facility with a group of banks. The
credit  facility  became  effective  November  22, 2002 and  includes a term-out
option that allows any outstanding borrowings at the end of the revolving credit
period to be repaid on November  21,  2004.  Exelon may increase or decrease the
sublimits of each of the participants upon written notification to the banks. As
of June 30, 2003, PECO's sublimit was $400 million.  The credit facility is used
by PECO principally to support its commercial  paper program.  At June 30, 2003,
PECO's  Consolidated  Balance Sheet  reflects  $170 million in commercial  paper
outstanding.  For the six months ended June 30, 2003, the average  interest rate
on notes payable was approximately 1.31%.

     The credit  facility  requires  PECO to maintain a cash from  operations to
interest expense ratio for the twelve-month  period ended on the last day of any
quarter.  The ratio  excludes  revenues and interest  expenses  attributable  to
securitization  debt,  certain changes in working capital and  distributions  on
preferred  securities of subsidiaries.  PECO's threshold for the ratio reflected
in the  credit  agreement  cannot be less  than  2.25 to 1 for the  twelve-month
period ended June 30, 2003. At June 30, 2003,  PECO was in  compliance  with the
credit agreement thresholds.

     To provide an additional short-term borrowing option that will generally be
more  favorable  to  the  borrowing  participants  than  the  cost  of  external
financing,  Exelon operates an  intercompany  money pool.  Participation  in the
money pool is subject to authorization by Exelon's corporate treasurer.  ComEd's
subsidiary,  Commonwealth Edison Company of Indiana,  Inc., PECO, Generation and
BSC may  participate  in the money pool as  lenders  and  borrowers,  and Exelon
Corporate and ComEd as lenders.  Funding of, and borrowings from, the money pool
are predicated on whether such funding  results in mutual  economic  benefits to
each of the participants,  although Exelon is not permitted to be a net borrower
from the money pool.  Interest on borrowings is based on short-term market rates
of interest,  or, if from an external source,  specific  borrowing rates.  There
were no material  money pool  transactions  by PECO during the six months  ended
June 30, 2003.

     PECO's  access to the  capital  markets,  including  the  commercial  paper
market, and its financing costs in those markets are dependent on its securities
ratings.  None of PECO's  borrowings  is subject to default or  prepayment  as a
result of a downgrading of securities  ratings although such a downgrading could
increase interest charges under certain bank credit facilities.

     Under PUHCA, PECO can pay dividends only from retained or current earnings.
At June 30, 2003, PECO had retained earnings of $455 million.

     Long-term debt included $4.1 billion of transition bonds.




                                      118
<PAGE>

              Contractual Obligations, Commercial Commitments and
                         Off-Balance Sheet Obligations

     Contractual  obligations  represent cash obligations that are considered to
be firm commitments and commercial  commitments  represent commitments triggered
by future events. PECO's contractual  obligations and commercial  commitments as
of June 30, 2003 were materially  unchanged,  other than in the normal course of
business,  from the  amounts  set  forth in the 2002 Form  10-K  except  for the
following:

o    PECO has entered into several  agreements with a tax consultant  related to
     the filing of refund claims with the IRS. The fees for these agreements are
     contingent upon a successful outcome and are based upon a percentage of the
     refunds  recovered from the IRS, if any. As such,  PECO would have positive
     net cash flows related to these  agreements if any fees are paid to the tax
     consultant.  These  potential  tax  benefits and  associated  fees could be
     material to the financial position, results of operations and cash flows of
     PECO.  PECO  cannot  predict  the timing of the final  resolution  of these
     refund claims.

o    See  Note 9 of the  Condensed  Combined  Notes  to  Consolidated  Financial
     Statements  for  further  discussion  of  material  changes in PECO's  debt
     obligations from those set forth in the 2002 Form 10-K.

o    See  Note 8 of the  Condensed  Combined  Notes  to  Consolidated  Financial
     Statements   for  commercial   commitments   tables   representing   PECO's
     commitments not recorded on the balance sheet but potentially  triggered by
     future  events,  including  obligations  to make payment on behalf of other
     parties and financing arrangements to secure their obligations.





                                      119
<PAGE>

EXELON GENERATION COMPANY, LLC
------------------------------
GENERAL

     Generation  operates  as a single  segment  and its  operations  consist of
electric generating facilities, energy marketing operations and equity interests
in Sithe and AmerGen.

RESULTS OF OPERATIONS

Three Months Ended June 30, 2003 Compared to Three Months Ended June 30, 2002

<TABLE>
<CAPTION>
Significant Operating Trends - Generation
                                                             Three Months Ended June 30,
                                                             ---------------------------
                                                                       2003         2002     Variance     % Change
-------------------------------------------------------------------------------------------------------------------
<S>                                                               <C>            <C>          <C>           <C>
OPERATING REVENUES                                                $   1,886      $ 1,559      $   327       21.0%

OPERATING EXPENSES
    Purchased power                                                     800          705           95       13.5%
    Fuel                                                                348          224          124       55.4%
    Operating and maintenance                                           451          411           40        9.7%
    Depreciation and amortization                                        46           65          (19)     (29.2%)
    Taxes other than income                                              40           41           (1)      (2.4%)
-------------------------------------------------------------------------------------------------------
         Total operating expenses                                     1,685        1,446          239       16.5%
-------------------------------------------------------------------------------------------------------

OPERATING INCOME                                                        201          113           88       77.9%
-------------------------------------------------------------------------------------------------------

OTHER INCOME AND DEDUCTIONS
    Interest expense                                                    (20)         (11)          (9)     (81.8%)
    Equity in earnings of unconsolidated affiliates                      18            9            9      100.0%
    Other, net                                                           34           24           10       41.7%
-------------------------------------------------------------------------------------------------------
         Total other income and deductions                               32           22           10       45.5%
-------------------------------------------------------------------------------------------------------

INCOME BEFORE INCOME TAXES                                              233          135           98       72.6%

INCOME TAXES                                                             91           51           40       78.4%
-------------------------------------------------------------------------------------------------------

NET INCOME                                                        $     142      $    84        $  58       69.0%
=======================================================================================================
</TABLE>


Net Income

     Generation's  net income  increased by $58  million,  or 69%, for the three
months ended June 30, 2003 compared to the same period in 2002  primarily due to
a $328 million  increase in market  electric  sales.  The increase was partially
offset  by an  increase  in fuel and  purchased  power  expense  related  to the
increase in market sales,  and a $74 million decrease in electric sales to other
Exelon businesses.

Operating Revenues

     Revenues increased by $327 million,  or 21% for the three months ended June
30, 2003  compared to the same period in 2002.  For the three  months ended June
30, 2003 and 2002, Generation's sales were as follows:




                                      120
<PAGE>

<TABLE>
<CAPTION>
                                                             Three Months Ended June 30,
                                                             ---------------------------
Revenue (in millions)                                                  2003         2002     Variance     % Change
-------------------------------------------------------------------------------------------------------------------
<S>                                                               <C>          <C>          <C>             <C>
Energy Delivery and Exelon Energy Company                         $     877    $     951    $     (74)      (7.8%)
Market Sales                                                            960          632          328       51.9%
------------------------------------------------------------------------------------------------------
Total Energy Sales Revenue                                            1,837        1,583          254       16.0%
Trading Portfolio                                                        (1)         (16)          15       93.8%
Other Revenue                                                            50           (8)          58       n.m.
------------------------------------------------------------------------------------------------------
Total Revenue                                                     $   1,886    $   1,559    $     327       21.0%
======================================================================================================
n.m. - not meaningful
                                                             Three Months Ended June 30,
                                                             ---------------------------
Sales (in GWhs)                                                        2003         2002     Variance     % Change
-------------------------------------------------------------------------------------------------------------------
Energy Delivery and Exelon Energy Company                            26,869       29,649       (2,780)      (9.4%)
Market Sales                                                         27,449       20,589        6,860       33.3%
------------------------------------------------------------------------------------------------------
Total Sales                                                          54,318       50,238        4,080        8.1%
======================================================================================================
</TABLE>

     Trading volume of 7,919 GWhs and 8,566 GWhs for the three months ended June
30,  2003 and  2002,  respectively,  is not  included  in the table  above.  The
decrease  in trading  volume is a result of reduced  volumetric  and VAR trading
limits in 2003,  which are set by the Risk Management  Committee and approved by
the Board of Directors.

     Generation's average revenue (per MWh) on energy sales for the three months
ended June 30, 2003 and 2002 is as follows:

<TABLE>
<CAPTION>
                                                                       Three Months Ended June 30,
                                                                       ---------------------------
 ($/MWh)                                                                   2003               2002        % Change
-------------------------------------------------------------------------------------------------------------------
<S>                                                                 <C>              <C>                     <C>
Average Revenue
    Energy Delivery and Exelon Energy Company                       $     32.67      $      32.06            1.9%
    Market Sales                                                          34.98             30.69           14.0%
    Total - excluding the trading portfolio                               33.83             31.50            7.4%
-------------------------------------------------------------------------------------------------------------------
</TABLE>

     Energy  Delivery  and  Exelon  Energy  Company.  Sales to  Energy  Delivery
decreased  by $57  million  primarily  due to  unfavorable  weather in ComEd and
PECO's service  territories during the three months ended June 30, 2003 compared
to the same period in 2002. Generation's average revenue per MWh was affected by
increased  prices per MWh for supply  agreements  with ComEd and PECO.  Sales to
Exelon Energy Company  decreased $17 million for the three months ended June 30,
2003 compared to the same period in 2002 primarily due to the  discontinuance of
Exelon Energy Company operations in the PJM region.

     Market  Sales.  The  increase  of  $328  million  resulted  primarily  from
increased  production  from  generating  assets acquired during 2002, as well as
lower load requirements to affiliates and higher wholesale market prices,  which
were primarily attributable to increased fossil fuel prices.

     Trading Revenues.  Trading activity  decreased revenue by $1 million during
the three months ended June 30, 2003 compared to $16 million for the same period
in 2002 due to reduced trading volume.

     Other  Revenues.  Other  revenues in the three  months  ended June 30, 2003
included $21 million from market gas sales,  and $18 million from ComEd  related
to nuclear decommissioning cost recoveries,  and $7 million of cost recoveries
from PECO.




                                      121
<PAGE>

Purchased Power and Fuel

     Generation's  supply  source  of its  sales and  average  supply  costs are
summarized below:

<TABLE>
<CAPTION>
                                                             Three Months Ended June 30,
                                                             ---------------------------
Supply of Sales (in GWhs)                                              2003         2002     Variance     % Change
-------------------------------------------------------------------------------------------------------------------
<S>                                                                 <C>          <C>           <C>          <C>
Purchases - non-trading portfolio (1)                                19,344       17,978        1,366        7.6%
Nuclear Generation (2)                                               29,619       28,776          843        2.9%
Fossil and Hydro Generation                                           5,355        3,484        1,871       53.7%
-----------------------------------------------------------------------------------------------------
Total Supply                                                         54,318       50,238        4,080        8.1%
=====================================================================================================
<FN>
(1) Including purchased power agreements with AmerGen.
(2) Excluding AmerGen.
</FN>
</TABLE>

<TABLE>
<CAPTION>
                                                                       Three Months Ended June 30,
                                                                       ---------------------------
 ($/MWh)                                                                   2003               2002        % Change
------------------------------------------------------------------------------------------------------------------
<S>                                                                <C>               <C>                   <C>
Average Supply Cost (1) - excluding trading portfolio               $     20.71       $     18.79           10.2%
------------------------------------------------------------------------------------------------------------------
<FN>
(1) Average supply cost includes purchased power and fuel costs.
</FN>
</TABLE>

     Generation's supply mix changed as a result of:

o    increased  nuclear  generation  due to a  lower  number  of  refueling  and
     unplanned outages during 2003 compared to 2002,
o    increased  fossil  generation  due to the effect of the Exelon New  England
     plants acquired in November 2002, which in total account for an increase of
     1,498 GWhs, and
o    increased  quantity of purchased  power at higher prices to serve  expected
     affiliate  load  obligations.  In addition,  Generation  entered into a new
     purchase  power  agreement with AmerGen in the second quarter of 2003. As a
     result, 1,258 GWhs were purchased from Oyster Creek nuclear facility in the
     second quarter of 2003.

     Purchased power  increased $95 million,  or 14%, for the three months ended
June 30, 2003 compared to the same period in 2002 due to a $125 million increase
related to higher market  prices and the delay of Exelon New England  commercial
operations  commencement  dates.  The increase in purchased  power was partially
offset by a $32 million gain on  mark-to-market  hedging  activity for the three
months  ended June 30, 2003  compared to a $4 million gain in the same period in
2002.

     Fuel expense  increased  $124  million,  or 55%, for the three months ended
June 30, 2003 compared to the same period in 2002, as summarized below:

<TABLE>
<CAPTION>
                                                             Three Months Ended June 30,
                                                             ---------------------------
 (in millions)                                                         2003         2002     Variance     % Change
-------------------------------------------------------------------------------------------------------------------
<S>                                                            <C>          <C>          <C>             <C>
Nuclear Generation (1)                                            $     132    $     120    $      12       10.0%
Fossil and Hydro Generation                                             216          104          112      107.7%
-----------------------------------------------------------------------------------------------------
Total                                                             $     348    $     224    $     124       55.4%
=====================================================================================================
<FN>
(1)      Excluding AmerGen
</FN>
</TABLE>

     This  increase is  primarily  due to a $92 million  increase in fossil fuel
generation  resulting from the acquisition of plant assets in 2002. In addition,
fuel expense  increased $10 million due to additional  nuclear fuel amortization
resulting  from  under  performing  fuel at the Quad  Cities  Unit 1,  which was
completely replaced in May 2003.




                                      122
<PAGE>

     Generation's  financial results are greatly dependent on the performance of
its nuclear units, including Generation's ability to maintain stable cost levels
and high nuclear capacity factors. Problems that may occur at nuclear facilities
that result in increased costs include  accelerated  replacement of suspect fuel
assemblies,  generation  reductions to make repairs and mid-cycle  outages.  For
example,  in the  second  quarter  of 2003,  the Quad  Cities  Unit 1 required a
significant  repair and is unable to operate above an 85% capacity  factor until
the Nuclear  Regulatory  Commission  (NRC) inspects and approves the maintenance
work.  Although this individual matter did not result in a significant  decrease
in  operating  income,  this  type of  reduction  in  operational  capacity  can
adversely affect  Generation's  financial  results.  Generation  anticipates NRC
approval of the maintenance  work and to return the unit to its normal operating
capacity in the near future.

Operating and Maintenance

     O&M expense increased $40 million,  or 10%, for the three months ended June
30, 2003  compared to the same period in 2002.  The  increase in O&M expense was
primarily  attributable to $46 million of accretion  expense related to SFAS No.
143, which includes $39 million of accretion of the asset retirement  obligation
and $7  million  to  adjust  the  earnings  impact  of  certain  of the  nuclear
decommissioning  revenues  earned from ComEd and PECO,  nuclear  decommissioning
trust fund investment income,  income taxes incurred on nuclear  decommissioning
trust  fund  activities,  accretion  of  the  asset  retirement  obligation  and
depreciation  of the  asset  retirement  cost  asset  to  zero,  $8  million  of
additional  employee  payroll and benefits costs,  and $19 million of additional
expenses due to asset  acquisitions made after the second quarter of 2002. Also,
Generation  recorded an  impairment  charge of $5 million in 2003 related to the
pending  retirement  of  Mystic  Station  Units 4, 5, and 6. This  increase  was
partially  offset  by $21  million  of lower  nuclear  refueling  outage  costs,
including $17 million for Generation's  ownership in Salem, which is operated by
the co-owner,  and other nonrecurring  charges in 2002. For a further discussion
of SFAS  No.  143 see Note 2 of the  Condensed  Combined  Notes to  Consolidated
Financial Statements.

<TABLE>
<CAPTION>
                                                                                          Three Months Ended June 30,
                                                                                          ---------------------------
                                                                                                 2003            2002
---------------------------------------------------------------------------------------------------------------------
<S>                                                                                   <C>               <C>
Nuclear fleet capacity factor (1)                                                             94.0%             92.1%
Nuclear fleet production cost per MWh (1)                                               $    12.08       $     12.54
Average purchased power cost for wholesale operations per MWh                           $    43.15       $     39.96
---------------------------------------------------------------------------------------------------------------------
<FN>
(1) Including AmerGen and excluding Salem.
</FN>
</TABLE>

     The higher nuclear capacity factor and decreased  nuclear  production costs
are primarily due to 20 fewer planned  refueling outage days,  resulting in a $4
million  decrease in outage  costs,  in the three  months ended June 30, 2003 as
compared to the same period in 2002.  Additionally,  the three months ended June
30, 2003 included nine unplanned  outages  compared to eight  unplanned  outages
during the same period in 2002.

Depreciation and Amortization

     Depreciation and amortization  expense  decreased $19 million,  or 29%, for
the three  months ended June 30, 2003  compared to the same period in 2002.  The
decrease   was   primarily   attributable   to  a  $31  million   reduction   in
decommissioning expense as these costs are included in operating and maintenance
expense  after the  adoption of SFAS No. 143,  and a $3 million  decrease due to
life  extensions of asset additions in 2002,  partially  offset by $4 million of
additional depreciation expense on capital additions placed in service after the
second quarter of 2002, $7 million related to plant  acquisitions made after the
second quarter of 2002, and $1




                                      123
<PAGE>

million of depreciation for the ARC asset related to SFAS No. 143. For a further
discussion  of SFAS  No.  143 see  Note 2 of the  Condensed  Combined  Notes  to
Consolidated Financial Statements.

Taxes Other Than Income

     Taxes other than income  decreased $1 million,  or 2%, for the three months
ended June 30, 2003  compared to the same period in 2002  primarily  due to a $1
million decrease in property taxes.

Interest Expense

     Interest expense  increased $9 million,  or 82%, for the three months ended
June 30, 2003  compared to the same period in 2002.  The increase was  primarily
due to a $7 million  decrease in  capitalized  interest,  $2 million of interest
expense on the $536 million note payable issued to Sithe in November 2002 and $2
million of  interest  expense on the  long-term  debt  obtained as a part of the
Sithe New England asset  acquisition.  This increase is partially offset by a $2
million  decrease in  interest  on  Generation's  spent fuel  obligation  to the
Department of Energy due to lower interest rates.

Equity in Earnings of Unconsolidated Affiliates

     Equity in earnings of unconsolidated  affiliates  increased $9 million,  or
100%,  for the three months  ended June 30, 2003  compared to the same period in
2002.  The increase  was due to a $18 million  increase in  Generation's  equity
earnings of AmerGen.  AmerGen's  earnings were  primarily  affected by increased
power  sales,  reduced  outage  costs,  and  favorable  impacts of SFAS 143. The
increase was partially  offset by a $9 million  decrease in Generation's  equity
earnings of Sithe.  Sithe's  earnings were  primarily  affected by  Generation's
purchase  of Sithe  New  England's  assets  in  November  2002  and  unfavorable
mark-to-market losses for the period at Sithe.

Other, Net

     Other,  net increased $10 million,  or 42%, for the three months ended June
30, 2003  compared to the same period in 2002.  The increase is primarily due to
higher  net  realized  gains  and  investment  income  related  to  the  nuclear
decommissioning  trust funds. These net realized gains and investment income are
almost  entirely  offset with  accretion  expense in 2003,  which is included in
operating and maintenance expense.

Income Taxes

     The effective income tax rate was 39.2% for the three months ended June 30,
2003 compared to 37.7% for the same period in 2002.  This increase was primarily
attributable  to an  increase in taxes  related to the  nuclear  decommissioning
trust funds.




                                      124
<PAGE>


     Six Months Ended June 30, 2003 Compared to Six Months Ended June 30, 2002

<TABLE>
<CAPTION>
Significant Operating Trends - Generation
                                                               Six Months Ended June 30,
                                                               -------------------------
                                                                       2003         2002     Variance     % Change
-------------------------------------------------------------------------------------------------------------------
<S>                                                               <C>            <C>          <C>           <C>
OPERATING REVENUES                                                $   3,765      $ 3,020      $   745       24.7%

OPERATING EXPENSES
    Purchased power                                                   1,642        1,323          319       24.1%
    Fuel                                                                706          433          273       63.0%
    Operating and maintenance                                           943          844           99       11.7%
    Depreciation and amortization                                        91          128          (37)     (28.9%)
    Taxes other than income                                              88           90           (2)      (2.2%)
------------------------------------------------------------------------------------------------------
         Total operating expenses                                     3,470        2,818          652       23.1%
------------------------------------------------------------------------------------------------------

OPERATING INCOME                                                        295          202           93       46.0%
------------------------------------------------------------------------------------------------------

OTHER INCOME AND DEDUCTIONS
    Interest expense                                                    (38)         (28)         (10)     (35.7%)
    Equity in earnings of unconsolidated affiliates                      37           32            5       15.6%
    Other, net                                                         (134)          40         (174)       n.m.
------------------------------------------------------------------------------------------------------
         Total other income and deductions                             (135)          44         (179)       n.m.
------------------------------------------------------------------------------------------------------

INCOME BEFORE INCOME TAXES AND CUMULATIVE
    EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES                          160          246          (86)     (35.0%)

INCOME TAXES                                                             71           96          (25)     (26.0%)
------------------------------------------------------------------------------------------------------

INCOME BEFORE CUMULATIVE EFFECT OF CHANGES IN
  ACCOUNTING PRINCIPLES                                                  89          150          (61)     (40.7%)

CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING
    PRINCIPLES, NET OF INCOME TAXES                                     108           13           95        n.m.
------------------------------------------------------------------------------------------------------

NET INCOME                                                        $     197      $   163        $  34       20.9%
======================================================================================================
n.m. - not meaningful
</TABLE>

Net Income

     Generation's  net income  increased  by $34  million,  or 21%,  for the six
months ended June 30, 2003  compared to the same period in 2002.  Income  before
cumulative effect of changes in accounting  principles  decreased by $61 million
for the six  months  ended June 30,  2003  compared  to the same  period in 2002
primarily  due  to the  after-tax  impairment  charge  for  Generation's  equity
investment in Sithe of $130 million,  partially  offset by higher revenue due to
increased market electric sales.




                                      125
<PAGE>

Operating Revenues

     Revenues  increased by $745  million,  or 25% for the six months ended June
30, 2003 compared to the same period in 2002.  For the six months ended June 30,
2003 and 2002, Generation's sales were as follows:

<TABLE>
<CAPTION>
                                                               Six Months Ended June 30,
                                                               -------------------------
Revenue (in millions)                                                  2003         2002     Variance     % Change
-------------------------------------------------------------------------------------------------------------------
<S>                                                               <C>          <C>             <C>           <C>
Energy Delivery and Exelon Energy Company                         $   1,842    $   1,839       $    3        0.2%
Market Sales                                                          1,863        1,175          688       58.6%
------------------------------------------------------------------------------------------------------
Total Energy Sales Revenue                                            3,705        3,014          691       22.9%
------------------------------------------------------------------------------------------------------
Trading Portfolio                                                        (2)         (15)          13      (86.7%)
Other Revenue                                                            62           21           41      195.2%
------------------------------------------------------------------------------------------------------
Total Revenue                                                     $   3,765    $   3,020       $  745       24.7%
======================================================================================================
n.m. - not meaningful
                                                               Six Months Ended June 30,
                                                               -------------------------
Sales (in GWhs)                                                        2003         2002     Variance     % Change
-------------------------------------------------------------------------------------------------------------------
Energy Delivery and Exelon Energy Company                            57,463       58,649       (1,186)      (2.0%)
Market Sales                                                         51,264       39,913       11,351       28.4%
------------------------------------------------------------------------------------------------------
Total Sales                                                         108,727       98,562       10,165       10.3%
======================================================================================================
</TABLE>

     Trading volume of 17,446 GWhs and 22,805 GWhs for the six months ended June
30,  2003 and  2002,  respectively,  is not  included  in the table  above.  The
decrease  in trading  volume is a result of reduced  volumetric  and VAR trading
limits in 2003,  which are set by the Risk Management  Committee and approved by
the Board of Directors.

     Generation's average revenue (per MWh) on energy sales for the three months
ended June 30, 2003 and 2002 is as follows:

<TABLE>
<CAPTION>
                                                                         Six Months Ended June 30,
                                                                         -------------------------
 ($/MWh)                                                                   2003               2002        % Change
-------------------------------------------------------------------------------------------------------------------
<S>                                                                 <C>              <C>                     <C>
Average Revenue
    Energy Delivery and Exelon Energy Company                       $     32.06      $      31.35            2.3%
    Market Sales                                                          35.94             29.44           22.1%
    Total - excluding the trading portfolio                               33.89             30.58           10.8%
-------------------------------------------------------------------------------------------------------------------
</TABLE>

     Energy  Delivery  and  Exelon  Energy  Company.  Sales to  Energy  Delivery
increased  by $22  million  as a result of  increased  prices per MWh for supply
agreements with ComEd and PECO,  partially offset by a net overall  reduction in
volume  demand  resulting  from  unfavorable   weather  and  customers  choosing
alternative suppliers under the customer choice program.  Sales to Exelon Energy
Company decreased by $19 million for the six months ended June 30, 2003 compared
to the same period in 2002 primarily due to the  discontinuance of Exelon Energy
Company operations in the PJM region.

     Market  Sales.  The  increase  of  $688  million  resulted  primarily  from
increased  production  from  generating  assets acquired during 2002, as well as
lower load  requirements  to  affiliates  and higher  wholesale  market  prices,
primarily attributable to higher fossil fuel prices.

     Trading Revenues. Trading activity reduced revenue by $2 million during the
six months ended June 30, 2003 compared to $15 million during the same period in
2002 due to lower trading activity.




                                      126
<PAGE>

     Other  Revenues.  Other  revenues  in the six months  ended  June 30,  2003
included  $31  million  from  ComEd  related  to  nuclear  decommissioning  cost
recoveries associated with the adoption of SFAS No. 143 that was not included in
revenues in 2002 and $27 million in gas sales.

Purchased Power and Fuel

     Generation's  supply  source  of its  sales and  average  supply  costs are
summarized below:

<TABLE>
<CAPTION>
                                                               Six Months Ended June 30,
                                                               -------------------------
Supply of Sales (in GWhs)                                              2003         2002     Variance     % Change
-------------------------------------------------------------------------------------------------------------------
<S>                                                                 <C>          <C>           <C>          <C>
Purchases - non-trading portfolio (1)                                39,373       36,071        3,302        9.2%
Nuclear Generation (2)                                               58,949       56,309        2,640        4.7%
Fossil and Hydro Generation                                          10,405        6,182        4,223       68.3%
-----------------------------------------------------------------------------------------------------
Total Supply                                                        108,727       98,562       10,165       10.3%
=====================================================================================================
<FN>
(1) Including purchased power agreements with AmerGen.
(2) Excluding AmerGen.
</FN>
</TABLE>

<TABLE>
<CAPTION>
                                                                        Six Months Ended June 30,
                                                                        -------------------------
($/MWh)                                                                   2003               2002        % Change
------------------------------------------------------------------------------------------------------------------
<S>                                                                <C>               <C>                   <C>
Average Supply Cost (1) - excluding trading portfolio               $     20.58       $     17.78           15.7%
------------------------------------------------------------------------------------------------------------------
<FN>
(1) Average supply cost includes purchased power and fuel costs.
</FN>
</TABLE>

     Generation's supply mix changed as a result of:

o    increased  nuclear  generation  due to a  lower  number  of  refueling  and
     unplanned outages during 2003 compared to 2002,
o    increased  fossil  generation  due to the effect of the  acquisition of two
     generating  plants in Texas in April 2002 and the Exelon New England plants
     acquired in November 2002,  which in total account for an increase of 2,995
     GWhs, and
o    increased  quantity  of  purchased  power at higher  prices.  In  addition,
     Generation  entered into a new purchase power agreement with AmerGen in the
     second quarter of 2003. As a result,  1,258 GWhs were purchased from Oyster
     Creek nuclear facility in the second quarter of 2003.

     Purchased  power  increased $319 million,  or 24%, for the six months ended
June 30, 2003 compared to the same period in 2002 due to $185 million related to
higher market prices and the delay of Exelon New England  commercial  operations
commencement dates. The increase in purchased power also reflects mark-to-market
hedging  gains of $1 million for the six months ended June 30, 2003  compared to
$10 million in the same period in 2002.

     Fuel expense increased $273 million,  or 63%, for the six months ended June
30, 2003 compared to the same period in 2002, as summarized below:

<TABLE>
<CAPTION>
                                                              Six Months Ended June 30,
                                                              -------------------------
(in millions)                                                         2003         2002     Variance     % Change
-----------------------------------------------------------------------------------------------------------------
<S>                                                            <C>          <C>          <C>              <C>
Nuclear Generation (1)                                            $     260    $     237    $      23        9.7%
Fossil and Hydro Generation                                             446          196          250      127.6%
-------------------------------------------------------------------------------------------------------
Total                                                             $     706    $     433    $     273       63.0%
=======================================================================================================
<FN>
(1)  Excluding AmerGen
</FN>
</TABLE>




                                      127
<PAGE>

     This  increase is primarily  due to the  increase in fossil fuel  generated
energy required to meet increased  market demand for energy and operation of new
base load  plants in New  England  as well as demand in all  regions  during the
first quarter of 2003. Fossil and other fuel expense increased $267 million,  as
a result of operating the generation plants acquired after the second quarter of
2002.  Increased  fossil fuel expense includes $149 million related to increased
market sales from the  generating  plants  acquired  after the second quarter of
2002.  Nuclear fuel expense  increased $23 million,  including $7 million due to
higher nuclear  generation and $16 million due to additional  fuel  amortization
resulting  from  under  performing  fuel at the Quad  Cities  Unit 1,  which was
completely  replaced in May 2003. These increases in fuel expense were partially
offset by a $4 million loss on emissions allowance sales recorded in 2002.

Operating and Maintenance

     O&M expense  increased  $99 million,  or 12%, for the six months ended June
30, 2003  compared to the same period in 2002.  The  increase in O&M expense was
primarily  attributable to $103 million of accretion expense related to SFAS No.
143, which includes $77 million of accretion of the asset retirement  obligation
and $26  million  to adjust  the  earnings  impact  of  certain  of the  nuclear
decommissioning  revenues  earned from ComEd and PECO,  nuclear  decommissioning
trust fund investment income,  income taxes incurred on nuclear  decommissioning
trust  fund  activities,  accretion  of  the  asset  retirement  obligation  and
depreciation  of the  asset  retirement  cost  asset to  zero,  $36  million  of
additional  employee  payroll and benefits costs,  and $38 million of additional
expenses due to asset  acquisitions made after the second quarter of 2002. Also,
Generation  recorded an  impairment  charge of $5 million in 2003 related to the
pending  retirement  of  Mystic  Station  Units 4, 5, and 6. This  increase  was
partially  offset  by $53  million  of lower  nuclear  refueling  outage  costs,
including $17 million for  Generation's  ownership  interest in Salem,  which is
operated by the co-owner,  a one-time  executive  severance  expense recorded in
2002 of $19 million,  an $8 million reduction in worker's  compensation  expense
and other non-recurring items. For a further discussion of SFAS No. 143 see Note
2 of the Condensed Combined Notes to Consolidated Financial Statements.

<TABLE>
<CAPTION>
                                                                                         Six Months Ended June 30,
                                                                                         -------------------------
                                                                                              2003            2002
---------------------------------------------------------------------------------------------------------------------
<S>                                                                                    <C>             <C>
Nuclear fleet capacity factor (1)                                                             94.2%           91.2%
Nuclear fleet production cost per MWh (1)                                               $    12.40       $    13.38
Average purchased power cost for wholesale operations per MWh                           $    41.71       $    36.76
---------------------------------------------------------------------------------------------------------------------
<FN>
(1) Including AmerGen and excluding Salem.
</FN>
</TABLE>

     The higher nuclear capacity factor and decreased  nuclear  production costs
are primarily due to 50 fewer planned refueling outage days,  resulting in a $36
million  decrease  in outage  costs,  in the six months  ended June 30,  2003 as
compared to the same period in 2002. Additionally, the six months ended June 30,
2003 included 11 unplanned  outages compared to 13 unplanned  outages during the
same period in 2002.

Depreciation and Amortization

     Depreciation and amortization  expense  decreased $37 million,  or 29%, for
the six months  ended June 30, 2003  compared  to the same  period in 2002.  The
decrease   was   primarily   attributable   to  a  $64  million   reduction   in
decommissioning expense as these costs are included in operating and maintenance
expense  after the  adoption of SFAS No. 143 and a $10 million  decrease  due to
life extensions of asset additions in 2002. The decrease was partially offset by
$10 million of additional  depreciation  expense on capital  additions placed in
service  after the




                                      128
<PAGE>

second  quarter of 2002,  $16 million of expense  related to plant  acquisitions
made after the second  quarter of 2002, and $2 million of  depreciation  for the
ARC asset related to SFAS No. 143. For a further  discussion of SFAS No. 143 see
Note 2 of the Condensed Combined Notes to Consolidated Financial Statements.

Taxes Other Than Income

     Taxes other than  income  decreased  $2 million,  or 2%, for the six months
ended June 30, 2003  compared to the same period in 2002  primarily  due to a $4
million  decrease in payroll taxes partially  offset by a $2 million increase in
property  taxes related to asset  acquisitions  made after the second quarter of
2002.

Interest Expense

     Interest  expense  increased $10 million,  or 36%, for the six months ended
June 30, 2003  compared to the same period in 2002.  The increase was  primarily
due to a $7 million decrease in capitalized interest. In addition,  the increase
was due to $5 million of  additional  interest  expense on the $536 million note
payable  issued to Sithe in November 2002 and $2 million of interest  expense on
the  long  term  debt  obtained  as a  part  of  the  Sithe  New  England  asset
acquisition.  This  increase  is  partially  offset by a $2 million  decrease in
interest on  Generation's  obligation  to the  Department of Energy due to lower
interest rates.

Equity in Earnings of Unconsolidated Affiliates

     Equity in earnings of unconsolidated  affiliates  increased $5 million,  or
16%, for the six months ended June 30, 2003 compared to the same period in 2002.
This increase was due to a $20 million increase in Generation's  equity earnings
in AmerGen. AmerGen's earnings were primarily affected by increased power sales,
reduced outage costs, and lower accretion expense resulting from the adoption of
SFAS No. 143.  The increase was  partially  offset by a $15 million  decrease in
Generation's equity earnings of Sithe.  Sithe's earnings were primarily affected
by  Generation's   purchase  of  Sithe  New  England's  assets  and  unfavorable
mark-to-market losses for the period at Sithe.

Other, Net

     Other,  net  decreased  $174 million for the six months ended June 30, 2003
compared to the same period in 2002.  This decrease is primarily a result of the
$200 million  impairment  charge related to  Generation's  equity  investment in
Sithe due to an other than temporary decline in value. This charge was partially
offset by $26 million of higher net realized gains and investment income related
to the  decommissioning  trust funds.  These net realized  gains and  investment
income are almost  entirely  offset  with  accretion  expense in 2003,  which is
included in operating and maintenance expense.

Income Taxes

     The  effective  income tax rate was 44.2% for the six months ended June 30,
2003  compared to 39.0% for the same period in 2002.  The increase was primarily
attributed to the impact of the impairment of  Generation's  investment in Sithe
as well as the increase in taxes  related to the nuclear  decommissioning  trust
funds.




                                      129
<PAGE>

     Due to revenue needs in the states in which  Generation  operates,  various
state income tax and fee increases have been proposed or are being contemplated.
If these changes are enacted,  they could increase Generation's state income tax
expense. At this time, however, Generation cannot predict whether legislation or
regulation  will be  introduced,  the  form of any  legislation  or  regulation,
whether  any  such  legislation  or  regulation  will  be  passed  by the  state
legislatures or regulatory bodies, and, if enacted, whether any such legislation
or regulation would be effective  retroactively or  prospectively.  As a result,
Generation cannot currently  estimate the effect of potential changes in tax law
or regulation.

Cumulative Effect of Changes in Accounting Principles

     On January 1, 2003,  Generation adopted SFAS No. 143 resulting in a benefit
of $108 million, net of income taxes of $70 million.

     On January 1, 2002,  Generation adopted SFAS No. 141 resulting in a benefit
of $13 million, net of income taxes of $9 million.

LIQUIDITY AND CAPITAL RESOURCES

     Generation's  business  is  capital  intensive  and  requires  considerable
capital  resources.  Generation's  capital  resources are primarily  provided by
internally  generated cash flows from operations  and, to the extent  necessary,
external financings including the issuance of commercial paper, participation in
the intercompany money pool or capital  contributions from Exelon.  Generation's
access to external  financing  at  reasonable  terms is  dependent on its credit
ratings and general business conditions, as well as that of the utility industry
in general.  If these  conditions  deteriorate to where Generation no longer has
access to external financing sources at reasonable terms,  Generation has access
to a revolving credit  facility.  See the Credit Issues section of Liquidity and
Capital Resources for further  discussion.  Capital resources are used primarily
to fund Generation's capital requirements,  including construction,  investments
in new and existing  ventures,  repayments  of maturing  debt and the payment of
dividends.   Any  future   acquisitions  could  require  external  financing  or
borrowings or capital contributions from Exelon.

     In the  second  quarter  of 2003,  Generation  progressed  in its  plans to
implement the new business  model  referred to as The Exelon Way. The Exelon Way
is focused on improving operating cash flows while meeting service and financial
commitments  through  improved  integration of operations and  consolidation  of
support functions.  As part of the implementation of The Exelon Way,  Generation
anticipates  incurring expenses  associated with the  rationalization of certain
business  functions  and  employee  separation  costs.  These  expenses  may  be
significant  and are expected to be incurred  during the remaining  half of 2003
through 2005. However, these costs cannot be reasonably estimated at this time.

Cash Flows from Operating Activities

     Cash flows  provided  by  operations  were $539  million for the six months
ended June 30, 2003,  compared to $519 million for the same period in 2002.  The
increase in cash flows from operating activities was primarily attributable to a
$114  million  increase  in  working  capital.  Cash  flows  used  in  operating
activities for collateral were $136 million as of June 30, 2003,




                                      130
<PAGE>

     compared to $30 million for the same period in 2002.  The  decrease in cash
flows from collateral  activities of $106 million was attributable to Generation
exceeding its negotiated  credit positions with  counterparties.  Cash flow used
for  collateral  will  depend upon  future  market  prices for energy and to the
extent forward energy deals are done under agreements with negotiated collateral
provisions.  When power  prices  return to  previous  levels or when  Generation
delivers the power under its forward conracts,  the collateral would be returned
to Generation  with no impact on its results of  operations.  Generation's  cash
flows from  operating  activities  primarily  result  from the sale of  electric
energy to wholesale customers,  including Generation's  affiliated companies, as
well as settlements arising from Generation's  trading activities.  Generation's
future cash flow from  operating  activities  will depend upon future demand and
market prices for energy and the ability to continue to produce and supply power
at competitive costs.

Cash Flows from Investing Activities

     Cash flows  used in  investing  activities  were $496  million  for the six
months  ended June 30, 2003,  compared to $1,048  million for the same period in
2002.  The decrease in cash flows used in  investing  activities  was  primarily
attributable  to a  reduction  in plant  acquisition  cost of $443  million as a
result of the acquisition of generating  plants during the six months ended June
30, 2002, and $86 million for liquidated  damages received from Raytheon in 2003
(see  Note  8  of  the  Condensed  Combined  Notes  to  Consolidated   Financial
Statements).  Generation's  proposed capital  expenditures and other investments
are  subject to  periodic  review and  revision  to reflect  changes in economic
conditions and other factors.

     Generation's  capital  expenditures  for 2003 reflect the  construction  of
three Exelon New England generating  facilities with projected capacity of 2,421
MWs of energy and  additions to and upgrades of existing  facilities  (including
nuclear  refueling  outages) and nuclear fuel.  During the six months ended June
30, 2003, Generation received $86 million of liquidated damages from Raytheon as
a result of  Raytheon  not  meeting  the  expected  completion  date and certain
contractual  performance criteria in connection with Raytheon's  construction of
the Mystic 8 and 9 and Fore River nuclear  generating  plants. In February 2002,
Generation  entered  into an  agreement  to loan AmerGen up to $75 million at an
interest rate of one-month  LIBOR plus 2.25%.  In July 2002,  the loan agreement
and the loan were  increased to $100 million and the maturity  date was extended
to July 1, 2003.  As of June 30,  2003,  AmerGen  has repaid the  balance of the
loan. Exelon anticipates that Generation's  capital  expenditures will be funded
by internally generated funds, borrowings or capital contributions from Exelon.

Cash Flows from Financing Activities

     Cash flows used in financing activities were $27 million for the six months
ended June 30, 2003, compared to cash flows provided by financing  activities of
$329  million for the same  period in 2002.  The  decrease  in cash  provided by
financing  was  primarily  due to a $273 million  decrease in cash receipts from
affiliates, $45 million dividend to Exelon Corporation, the $210 million partial
payment of the acquisition  note payable to Sithe, and a $38 million decrease in
restricted  cash as a result of  liquidated  damages  received  from Raytheon in
2003. The decrease in cash provided by financing activities was partially offset
by $211 million of borrowings under the revolving credit facility. See Note 9 of
the Condensed  Combined Notes to Consolidated  Financial  Statements for further
discussion of Generation's debt financing activities.





                                      131
<PAGE>

Credit Issues

     Generation meets its short-term  liquidity  requirements  primarily through
intercompany  borrowings  from  Exelon,  the  issuance of  commercial  paper and
participation in the  intercompany  money pool.  Generation,  along with Exelon,
ComEd and PECO,  participates  in a $1.5  billion  unsecured  364-day  revolving
credit facility with a group of banks.  The credit facility became  effective on
November  22, 2002 and  includes a term-out  option that allows any  outstanding
borrowings  at the end of the  revolving  credit period to be repaid on November
21,  2004.  Exelon  may  increase  or  decrease  the  sublimits  of  each of the
participants  upon written  notification  to the banks. As of June 30, 2003, the
sublimit for Generation was zero. The credit  facility is expected to be used by
Generation principally to support its commercial paper program.

     The credit facility requires  Generation to maintain a cash from operations
to interest expense ratio for the  twelve-month  period ended on the last day of
any quarter.  The ratio excludes  certain changes in working  capital,  revenues
from Exelon New England and interest on the debt of Exelon New England's project
subsidiaries.  Generation's  threshold  for the ratio  reflected  in the  credit
agreement cannot be less than 3.25 to 1 for the  twelve-month  period ended June
30,  2003.  At June 30,  2003,  Generation  was in  compliance  with the  credit
agreement thresholds.

     To provide an additional short-term borrowing option that will generally be
more  favorable  to  the  borrowing  participants  than  the  cost  of  external
financing,  Exelon operates an  intercompany  money pool.  Participation  in the
money pool is  subject  to  authorization  by the  Exelon  corporate  treasurer.
ComEd's  subsidiary,   Commonwealth  Edison  Company  of  Indiana,  Inc.,  PECO,
Generation  and BSC may  participate in the money pool as lenders and borrowers,
and Exelon Corporate and ComEd as lenders.  Funding of, and borrowings from, the
money pool are  predicated  on whether such funding  results in mutual  economic
benefits to each of the  participants,  although Exelon is not permitted to be a
net borrower from the money pool.  Interest on borrowings is based on short-term
market rates of interest,  or, if from an external  source,  specific  borrowing
rates.  During  the six months  ended  June 30,  2003,  Generation  had  various
borrowings  from  ComEd  under  the  money  pool.  The  maximum  amount of loans
outstanding  at any time  during the quarter  was $342  million.  As of June 30,
2003,  Generation  owed ComEd $165  million on these  loans.  For the six months
ended June 30, 2003, Generation paid $1 million in interest to ComEd

     EBG, an indirect  subsidiary of Generation,  has approximately $1.1 billion
of debt  outstanding  under the EBG Facility at June 30, 2003.  The EBG Facility
was entered into primarily to finance the construction of the Mystic 8 and 9 and
Fore River generating  units. The EBG Facility requires that all of the projects
achieve "Project  Completion," as defined in the EBG Facility, by June 12, 2003.
On June 11, 2003, EBG negotiated an extension of the Project  Completion date to
July 11,  2003.  On July 3, 2003,  the lenders  under the EBG  Facility  and EBG
executed  a letter  agreement  as a result of which the  lenders  are  precluded
during the period July 11, 2003  through  August 29,  2003 from  exercising  any
remedies  resulting  from the failure of all of the projects to achieve  Project
Completion.  At that time,  EBG stated  that it would  continue  to monitor  the
projects,  assess all of its options  relating  to the  projects,  and  continue
discussions  with  the  lenders.  Mystic  8 and 9 are in  commercial  operation,
although  construction  has not




                                      132
<PAGE>

progressed  to the point of Project  Completion.  Construction  of Fore River is
substantially  complete and the unit is currently  undergoing testing.  EBG does
not anticipate that the projects will achieve  Project  Completion by August 29,
2003. The EBG Facility is  non-recourse to Exelon and Generation and an event of
default under the EBG Facility does not constitute an event of default under any
other debt instruments of Exelon or its subsidiaries.

     As  a  result  of  Exelon's  continuing  evaluation  of  the  projects  and
discussions  with the lenders in July 2003,  Exelon has commenced the process of
an  orderly  transition  out of the  ownership  of EBG  and  the  projects.  The
transition will take place in a manner that complies with applicable  regulatory
requirements.  For a period of time,  Exelon  expects  to  continue  to  provide
administrative and operational services to EBG in its operation of the projects.
Exelon  informed  the lenders of Exelon's  decision to exit and that it will not
provide  additional  funding to the  projects  beyond its  existing  contractual
obligations. Exelon cannot predict the timing of the transition.

     Exelon  expects  Generation  will incur an  impairment  of its EBG  related
assets, which, in aggregate, could reach approximately $550 million after income
taxes.

     The debt outstanding  under the EBG Facility of approximately  $1.1 billion
at June 30, 2003 is reflected in  Generation's  Consolidated  Balance Sheet as a
current liability.

     On June 13, 2003,  Generation  entered into a $550 million revolving credit
facility.  Generation  used the  facility  to make the  first  payment  to Sithe
relating to the $536 million note that was used to purchase the EBG  facilities.
This note was restructured in June 2003 to provide for a payment of $210 million
of the principal on June 16, 2003 and payment of the remaining  principal on the
earlier of December 1, 2003 or change of control.

     Generation's access to the capital markets and its financing costs in those
markets are dependent on its securities ratings. None of Generation's borrowings
is subject to default or prepayment  as a result of a downgrading  of securities
ratings  although  such a  downgrading  could  increase  interest  charges under
certain bank credit facilities.  From time to time Generation enters into energy
commodity and other  derivative  transactions  that require the  maintenance  of
investment  grade ratings.  Failure to maintain  investment  grade ratings would
allow the counterparty to terminate the derivative and settle the transaction on
a net present value basis.

     Under  PUHCA,  Generation  can only pay  dividends  from  undistributed  or
current  earnings.  Generation is precluded from lending or extending  credit or
indemnity to Exelon. At June 30, 2003, Generation had undistributed  earnings of
$1.1 billion.




                                      133
<PAGE>

Contractual Obligations, Commercial Commitments and Off-Balance Sheet
Obligations

     Contractual  obligations  represent cash obligations that are considered to
be firm commitments and commercial  commitments  represent commitments triggered
by  future  events.   Generation's   contractual   obligations   and  commercial
commitments as of June 30, 2003 were  materially  unchanged from the amounts set
forth in the 2002 Form 10-K except for the following:

     o    Generation entered into a PPA dated June 26, 2003 with AmerGen.  Under
          the PPA, Generation has agreed to purchase 100% of energy generated by
          Oyster  Creek  through  April 9,  2009.  See  Note 8 of the  Condensed
          Combined  Notes to  Consolidated  Financial  Statements for commercial
          commitments tables representing  Generation's commitments not recorded
          on the  balance  sheet but  potentially  triggered  by future  events,
          including  obligations  to make payment on behalf of other parties and
          financing arrangements to secure their obligations.

     o    On  May  29,  2003,  Exelon  Fossil  Holdings,  Inc.,  a  wholly-owned
          subsidiary of Generation,  issued an  irrevocable  call notice for the
          35.2%  interest  in Sithe  owned by Apollo  Energy,  LLC and the 14.9%
          interest owned by subsidiaries of Marubeni Corporation. The total call
          price was based on the terms of the  existing  Put and Call  Agreement
          (PCA) among the parties and approximated $650 million. The transfer of
          ownership  requires various regulatory  approvals  including FERC, the
          state  environmental  agency in New Jersey, and expiration of the Hart
          Scott Rodino waiting period.

               Under the terms of the PCA,  the call must be funded  within  six
          months of the call  notice  being  issued.  Additionally,  because the
          Federal  Power  Act  restricts  Exelon's  ownership  of 50% or more of
          Qualifying  Facilities  (QFs),  the QFs owned by Sithe must be sold or
          restructured  before closing to preserve their QF status.  Despite the
          issuance of the call notice, Generation continues to pursue options to
          sell its investment in Sithe in its entirety.

     o    In June  2003,  Generation  entered  an  agreement  with USEC Inc.  to
          purchase  approximately $700 million of nuclear fuel from 2005 through
          2010.

     As  discussed in Note 2 of the  Condensed  Combined  Notes to  Consolidated
Financial Statements, it is reasonably possible that Generation will consolidate
Sithe as of July 1, 2003  pursuant  to FIN No. 46,  "Consolidation  of  Variable
Interest Entities."

     At December 31, 2002, Sithe had total assets of $2.6 billion (including the
$534 million note from Generation  which has  subsequently  been reduced to $326
million) and total liabilities of $1.8 billion. Of the total liabilities,  Sithe
had $1.3 billion of debt which included $624 million of subsidiary debt incurred
primarily to finance the  construction  of six new generating  facilities,  $461
million of  subordinated  debt, $103 million of line of credit  borrowings,  $43
million of current portion of long-term debt and capital leases,  $30 million of
capital leases,  and excludes $453 million of non-recourse  debt associated with
Sithe's  equity  investments.  For the year ended  December 31, 2002,  Sithe had
revenues of approximately  $1.0 billion and incurred a net




                                      134
<PAGE>

loss of  approximately  $348  million.  Exelon  contractually  does  not own any
interest in Sithe  International,  a subsidiary of Sithe.  As such, a portion of
Sithe's  net  assets  and  results  of  operations   would  be  eliminated  from
Generation's  balance  sheet  and  results  of  operations  through  a  minority
interest.


ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

Commodity Price Risk
Generation

     Commodity price risk is associated  with market price  movements  resulting
from excess or insufficient generation,  changes in fuel costs, market liquidity
and other factors.  Trading  activities  and  non-trading  marketing  activities
include the purchase and sale of electric  capacity and energy and fossil fuels,
including oil, gas, coal and emission allowances. The availability and prices of
energy and energy-related commodities are subject to fluctuations due to factors
such as  weather,  governmental  environmental  policies,  changes in supply and
demand, state and Federal regulatory policies and other events.

Normal Operations and Hedging Activities

     Electricity  available  from  Generation's  owned or contracted  generation
supply in excess of its obligations to customers,  including  Energy  Delivery's
retail load, is sold into the wholesale markets.  To reduce price risk caused by
market  fluctuations,  Generation  enters  into  physical  contracts  as well as
derivative  contracts,  including forwards,  futures,  swaps, and options,  with
approved  counterparties to hedge its anticipated exposures.  The maximum length
of time over which cash flows related to energy  commodities are currently being
hedged is four years.  Generation  has an estimated  91% hedge ratio in 2003 for
its energy  marketing  portfolio.  This hedge ratio represents the percentage of
Generation's  forecasted  aggregate  annual economic  generation  supply that is
committed to firm sales,  including sales to ComEd and PECO's retail load. ComEd
and PECO's retail load assumptions are based on forecasted  average demand.  The
hedge ratio is not fixed and will vary from time to time  depending  upon market
conditions, demand, and energy market option volatility and actual loads. During
peak  periods,  the amount hedged  declines to meet the  commitment to ComEd and
PECO.  Market  price  risk  exposure  is the  risk of a change  in the  value of
unhedged  positions.  Absent any opportunistic  efforts to mitigate market price
exposure,  the  estimated  market price  exposure for  Generation's  non-trading
portfolio  associated  with  a ten  percent  reduction  in  the  annual  average
around-the-clock  market price of  electricity is an  approximately  $37 million
decrease in net  income,  or  approximately  $0.11 per share.  This  sensitivity
assumes a consistent hedge ratio and that price changes occur evenly  throughout
the  year  and  across  all  markets.  The  sensitivity  also  assumes  a static
portfolio.  Generation  expects to  actively  manage its  portfolio  to mitigate
market price  exposure.  Actual  results could differ  depending on the specific
timing of, and markets affected by, price changes,  as well as future changes in
Generation's portfolio.




                                      135
<PAGE>

Proprietary Trading Activities

     Generation  uses  financial  contracts for  proprietary  trading  purposes.
Proprietary  trading  includes all contracts  entered into purely to profit from
market price  changes as opposed to hedging an exposure.  These  activities  are
accounted for on a mark-to-market  basis. The proprietary trading activities are
a complement to  Generation's  energy  marketing  portfolio and represent a very
small portion of its overall energy marketing activities. For example, the limit
on open positions in electricity  for any forward month  represents less than 1%
of  Generation's  owned  and  contracted  supply  of  electricity.  The  trading
portfolio is subject to stringent risk management limits and policies, including
volume, stop-loss and value-at-risk limits.

     Generation's  energy  contracts  are  accounted  for  under  SFAS No.  133,
"Accounting for Derivative  Instruments and Hedging  Activities" (SFAS No. 133).
Most  non-trading  contracts  qualify for the normal  purchases and normal sales
exemption to SFAS No. 133 discussed in the Critical Accounting Estimates section
of  Management's  Discussion  and Analysis of Financial  Condition and Result of
Operations  of the 2002 Form 10-K.  Those that do not are  recorded as assets or
liabilities  on the balance  sheet at fair  value.  Changes in the fair value of
qualifying hedge contracts are recorded in Other Comprehensive Income (OCI), and
gains and losses are  recognized  in earnings  when the  underlying  transaction
occurs. Changes in the fair value of derivative contracts that do not meet hedge
criteria under SFAS No. 133 and the  ineffective  portion of hedge contracts are
recognized in earnings on a current basis.

     The  following  detailed   presentation  of  the  trading  and  non-trading
marketing  activities  at  Generation  is included  to address  the  recommended
disclosures  by  the  energy  industry's   Committee  of  Chief  Risk  Officers.
Generation  does  not  consider  its  proprietary  trading  to be a  significant
activity  in its  business;  however,  Generation  believes it is  important  to
include these risk management disclosures.




                                      136
<PAGE>

     The following  tables describe the drivers of  Generation's  energy trading
and marketing business and gross margin included in the income statement for the
three  and six  months  ended  June 30,  2003.  Normal  operations  and  hedging
activities  represent the marketing of electricity  available from  Generation's
owned or contracted  generation,  including  ComEd and PECO's retail load,  sold
into the  wholesale  market.  As the  information  in these  tables  highlights,
mark-to-market  activities represent a small portion of the overall gross margin
for  Generation.  Accrual  activities,  including  normal  purchases  and sales,
account for the  majority of the gross  margin.  The  mark-to-market  activities
reported  here are those  relating  to  changes  in fair  value due to  external
movement  in  prices.  Further  delineation  of  gross  margin  by the  type  of
accounting  treatment typically afforded each type of activity is also presented
(i.e., mark-to-market vs. accrual accounting treatment).

<TABLE>
<CAPTION>
                                                                                  Three Months Ended June 30, 2003
                                                             -----------------------------------------------------
                                                              Normal Operations and       Proprietary
                                                                 Hedging Activities (a)       Trading        Total
-------------------------------------------------------------------------------------------------------------------
<S>                                                                      <C>              <C>                <C>
Mark-to-market activities:
--------------------------
Unrealized mark-to-market gain/(loss)
   Origination unrealized gain/(loss) at inception                       $       --       $       --        $   --
   Changes in fair value prior to settlements                                   109               (1)          108
   Changes in valuation techniques and assumptions                               --               --            --
   Reclassification to realized at settlement of contracts                      (77)              (1)          (78)
-------------------------------------------------------------------------------------------------------------------
   Total change in unrealized fair value                                         32               (2)           30
Realized net settlement of transactions subject to mark-to-market                77                1            78
-------------------------------------------------------------------------------------------------------------------
Total mark-to-market activities gross margin                             $      109       $       (1)       $  108
-------------------------------------------------------------------------------------------------------------------

Accrual activities:
-------------------
Accrual activities revenue                                               $    1,107       $       --        $ 1,107
Hedge gains/(losses) reclassified from OCI                                      616               --           616
-------------------------------------------------------------------------------------------------------------------
   Total revenue - accrual activities                                         1,723               --         1,723
-------------------------------------------------------------------------------------------------------------------
Purchased power and fuel                                                        388               --           388
Hedges of purchased power and fuel reclassified from OCI                        705               --           705
-------------------------------------------------------------------------------------------------------------------
   Total purchased power and fuel                                             1,093               --         1,093
-------------------------------------------------------------------------------------------------------------------
   Total accrual activities gross margin                                        630               --           630
-------------------------------------------------------------------------------------------------------------------
Total gross margin                                                      $       739       $       (1)    $     738 (b)
===================================================================================================================
<FN>
(a)  Normal Operations and Hedging Activities only include derivative  contracts
     Generation enters into to hedge anticipated  exposures related to its owned
     and  contracted  generation  supply,  but excludes its owned and contracted
     generating assets.
(b)  Total Gross Margin  represents  revenue,  net of  purchased  power and fuel
     expense for Generation.
</FN>
</TABLE>





                                      137
<PAGE>


<TABLE>
<CAPTION>
                                                                                    Six Months Ended June 30, 2003
                                                             -----------------------------------------------------
                                                              Normal Operations and       Proprietary
                                                                 Hedging Activities (a)       Trading        Total
------------------------------------------------------------------------------------------------------------------
<S>                                                                      <C>              <C>             <C>
Mark-to-market activities:
--------------------------
Unrealized mark-to-market gain/(loss)
   Origination unrealized gain/(loss) at inception                       $       --       $       --      $     --
   Changes in fair value prior to settlements                                   135               (3)          132
   Changes in valuation techniques and assumptions                               --               --            --
   Reclassification to realized at settlement of contracts                     (134)              (1)         (135)
------------------------------------------------------------------------------------------------------------------
   Total change in unrealized fair value                                          1               (4)           (3)
Realized net settlement of transactions subject to mark-to-market               134                1           135
------------------------------------------------------------------------------------------------------------------
Total mark-to-market activities gross margin                             $      135       $       (3)     $    132
------------------------------------------------------------------------------------------------------------------

Accrual activities:
-------------------
Accrual activities revenue                                               $    2,459       $       --      $  2,459
Hedge gains/(losses) reclassified from OCI                                    1,014               --         1,014
------------------------------------------------------------------------------------------------------------------
   Total revenue - accrual activities                                         3,473               --         3,473
------------------------------------------------------------------------------------------------------------------
Purchased power and fuel                                                        980               --           980
Hedges of purchased power and fuel reclassified from OCI                      1,208               --         1,208
------------------------------------------------------------------------------------------------------------------
   Total purchased power and fuel                                             2,188               --         2,188
------------------------------------------------------------------------------------------------------------------
   Total accrual activities gross margin                                      1,285               --         1,285
------------------------------------------------------------------------------------------------------------------
Total gross margin                                                      $     1,420       $       (3)    $   1,417 (b)
==================================================================================================================
<FN>
(a) Normal  Operations  and  Hedging  Activities  only  include  derivative
    contracts Generation enters into to hedge anticipated exposures related
    to its owned and contracted  generation  supply, but excludes its owned
    and contracted generating assets.
(b) Total Gross Margin represents revenue,  net of purchased power and fuel
    expense for Generation.
</FN>
</TABLE>






                                      138
<PAGE>

     The   following   table   provides   detail  on  changes  in   Generation's
mark-to-market  net asset or liability  balance  sheet  position from January 1,
2003 to June 30, 2003.  It indicates the drivers  behind  changes in the balance
sheet amounts.  This table will incorporate the  mark-to-market  activities that
are immediately recorded in earnings, as shown in the previous table, as well as
the  settlements  from OCI to earnings and changes in fair value for the hedging
activities that are recorded in Accumulated  Other  Comprehensive  Income on the
June 30, 2003 Consolidated Balance Sheet.

<TABLE>
<CAPTION>
                                                                      Normal Operations and  Proprietary
                                                                         Hedging Activities      Trading     Total
-------------------------------------------------------------------------------------------------------------------
<S>                                                                              <C>          <C>          <C>
Total mark-to-market energy contract net assets
    (liabilities) at January 1, 2003                                              $    (168)   $       5    $ (163)
Total change in fair value for the six months ended June 30, 2003
     of contracts recorded in earnings                                                  135           (3)      132
Reclassification to realized at settlement of contracts recorded in earnings           (134)          (1)     (135)
Reclassification to realized at settlement from OCI                                     194           --       194
Effective portion of changes in fair value - recorded in OCI                           (367)          --      (367)
Purchase/sale of existing contracts or portfolios subject to mark-to-market              --           --        --
------------------------------------------------------------------------------------------------------------------
Total mark-to-market energy contract net assets (liabilities)
    at June 30, 2003                                                              $    (340)   $       1    $ (339)
==================================================================================================================
</TABLE>

     The  following  table  details  the  balance  sheet  classification  of the
mark-to-market energy contract net assets recorded as of June 30, 2003:

<TABLE>
<CAPTION>
                                                                   Normal Operations and   Proprietary
                                                                      Hedging Activities       Trading       Total
------------------------------------------------------------------------------------------------------------------
<S>                                                                           <C>            <C>         <C>
Current assets                                                                $      251     $       2   $     253
Noncurrent assets                                                                     68            --          68
------------------------------------------------------------------------------------------------------------------
   Total mark-to-market energy contract assets                                       319             2         321
------------------------------------------------------------------------------------------------------------------

Current liabilities                                                                (490)            --        (490)
Noncurrent liabilities                                                             (169)           (1)        (170)
------------------------------------------------------------------------------------------------------------------
   Total mark-to-market energy contract liabilities                                (659)           (1)        (660)
------------------------------------------------------------------------------------------------------------------
Total mark-to-market energy contract net assets (liabilities)                 $    (340)     $      1    $    (339)
==================================================================================================================
</TABLE>




                                      139
<PAGE>

     The majority of Generation's  contracts are  non-exchange  traded contracts
valued using prices provided by external  sources,  primarily  price  quotations
available through brokers or over-the-counter, on-line exchanges. Prices reflect
the average of the  bid-ask  midpoint  prices  obtained  from all  sources  that
Generation believes provide the most liquid market for the commodity.  The terms
for which such price information is available varies by commodity, by region and
by product.  The remainder of the assets represents contracts for which external
valuations are not available,  primarily option  contracts.  These contracts are
valued using the Black model, an industry  standard option  valuation model. The
fair values in each category  reflect the level of forward prices and volatility
factors  as of June 30,  2003 and may  change  as a result of  changes  in these
factors.  Management  uses its best  estimates  to  determine  the fair value of
commodity and derivative  contracts it holds and sells. These estimates consider
various  factors   including   closing  exchange  and   over-the-counter   price
quotations,  time value, volatility factors and credit exposure. It is possible,
however,  that  future  market  prices  could vary from those used in  recording
assets and  liabilities  from energy  marketing and trading  activities and such
variations could be material.

     The following  table,  which presents  maturity and source of fair value of
mark-to-market  energy contract net assets,  provides two fundamental  pieces of
information.  First,  the  table  provides  the  source  of fair  value  used in
determining the carrying amount of Generation's  total  mark-to-market  asset or
liability.  Second,  this table provides the maturity,  by year, of Generation's
net  assets/liabilities,  giving  an  indication  of when  these  mark-to-market
amounts will settle and generate or require cash.

<TABLE>
<CAPTION>
                                                                                                    Maturities within
                                                         ------------------------------------------------------------
                                                                                                2008 and   Total Fair
                                                             2003   2004    2005    2006   2007   Beyond       Value
---------------------------------------------------------------------------------------------------------------------
<S>                                                       <C>      <C>     <C>    <C>     <C>     <C>        <C>
Normal Operations, qualifying cash flow hedge contracts (1):
  Prices provided by other external sources               $(190)   $(150)  $ (11) $   (7) $  --   $   --     $  (358)
---------------------------------------------------------------------------------------------------------------------
  Total                                                   $(190)   $(150)  $ (11) $   (7) $  --   $   --     $  (358)
---------------------------------------------------------------------------------------------------------------------

Normal Operations, other derivative contracts (2):
   Actively quoted prices                                 $   18   $   8   $  --  $   --  $  --   $   --     $    26
   Prices provided by other external sources                   6      16       5       4     --       --          31
   Prices based on model or other valuation methods           12     (34)     (5)     (9)    (3)      --         (39)
---------------------------------------------------------------------------------------------------------------------
  Total                                                   $   36   $ (10)  $  --  $   (5) $  (3)  $   --     $    18
---------------------------------------------------------------------------------------------------------------------

Proprietary Trading, other derivative contracts (3):
   Actively quoted prices                                 $    1   $   2   $  --  $   --  $  --   $   --     $     3
   Prices provided by other external sources                  (1)     (5)     --      --     --       --          (6)
   Prices based on model or other valuation methods            3       1      --      --     --       --           4
---------------------------------------------------------------------------------------------------------------------
  Total                                                   $    3   $  (2)  $  --  $   --  $  --   $   --     $     1
---------------------------------------------------------------------------------------------------------------------
Average tenor of proprietary trading portfolio (4)                                                          1.5 years
=====================================================================================================================
<FN>
(1)  Mark-to-market  gains and  losses on  contracts  that  qualify as cash flow
     hedges are recorded in other comprehensive income.
(2)  Mark-to-market  gains and losses on other non-trading  derivative contracts
     that do not qualify as cash flow hedges are recorded in earnings.
(3)  Mark-to-market  gains and  losses on  trading  contracts  are  recorded  in
     earnings.
(4)  Following the recommendations of the Committee of Chief Risk Officers,  the
     average tenor of the  proprietary  trading  portfolio  measures the average
     time to collect value for that portfolio.  Generation measures the tenor by
     separating positive and negative  mark-to-market  values in its proprietary
     trading  portfolio,  estimating  the  mid-point  in years for each and then
     reporting the highest of the two mid-points  calculated.  In the event that
     this methodology resulted in significantly different absolute values of the
     positive and negative cash flow streams, Generation would use the mid-point
     of the portfolio with the largest cash flow stream as the tenor.
</FN>
</TABLE>




                                      140
<PAGE>

     The table below  provides  details of effective cash flow hedges under SFAS
No. 133 included in the balance sheet as of June 30, 2003. The data in the table
gives an indication of the  magnitude of SFAS No. 133 hedges  Generation  has in
place,  however,  given that under SFAS No. 133 not all hedges are  recorded  in
OCI,  the table does not  provide an  all-encompassing  picture of  Generation's
hedges.   The  table  also  includes  a  roll-forward   of   Accumulated   Other
Comprehensive  Income on the  Consolidated  Balance  Sheets related to cash flow
hedges  for the six months  ended  June 30,  2003,  providing  insight  into the
drivers of the changes (new hedges entered into during the period and changes in
the value of existing hedges). Information related to energy merchant activities
is presented separately from interest rate hedging activities.

<TABLE>
<CAPTION>
                                                             Total Cash Flow Hedge Other Comprehensive Income Activity,
                                                                                                     Net of Income Tax
----------------------------------------------------------------------------------------------------------------------
                                                       Normal Operations and     Interest Rate and          Total Cash
                                                           Hedging Activities      Other Hedges (1)        Flow Hedges
----------------------------------------------------------------------------------------------------------------------
<S>                                                            <C>                <C>                 <C>
Accumulated OCI, January 1, 2003                                 $       (114)      $           (5)     $     (119)
Changes in fair value                                                    (223)                 (12)           (235)
Reclassifications from OCI to net income                                  119                   --             119
----------------------------------------------------------------------------------------------------------------------
Accumulated OCI derivative gain/(loss)
   at June 30, 2003                                              $       (218)      $          (17)      $    (235)
======================================================================================================================
<FN>
(1) Includes interest rate hedges at Generation.
</FN>
</TABLE>

     Generation  uses a  Value-at-Risk  (VaR)  model to assess the  market  risk
associated with financial  derivative  instruments  entered into for proprietary
trading  purposes.  The measured  VaR  represents  an estimate of the  potential
change in value of Generation's proprietary trading portfolio.

     The VaR estimate  includes a number of  assumptions  about  current  market
prices,  estimates of volatility and correlations between market factors.  These
estimates,  however, are not necessarily indicative of actual results, which may
differ  because  actual  market rate  fluctuations  may differ  from  forecasted
fluctuations and because the portfolio may change over the holding period.

     Generation  estimates VaR using a model based on the Monte Carlo simulation
of commodity  prices that captures the change in value of forward  purchases and
sales as well as option  values.  Parameters  and values are back  tested  daily
against daily changes in mark-to-market  value for proprietary trading activity.
VaR assumes that normal market conditions  prevail and that there are no changes
in positions. Generation uses a 95% confidence interval, one-day holding period,
one-tailed   statistical  measure  in  calculating  its  VaR.  This  means  that
Generation  may  state  that  there is a one in 20 chance  that if  prices  move
against its portfolio  positions,  its pre-tax loss in liquidating its portfolio
in a one-day  holding  period  would exceed the  calculated  VaR. To account for
unusual events and loss of liquidity,  Generation uses stress tests and scenario
analysis.

     For financial reporting purposes only,  Generation calculates several other
VaR estimates.  The higher the confidence  interval,  the less likely the chance
that the VaR estimate would be exceeded.  A longer holding period  considers the
effect of  liquidity  in being  able to  actually




                                      141
<PAGE>

liquidate the portfolio.  A two-tailed  test considers  potential  upside in the
portfolio in addition to the potential  downside in the portfolio  considered in
the one-tailed  test. The following  table provides the VaR for all  proprietary
trading positions of Generation as of June 30, 2003.

                                                                Proprietary
                                                                Trading VaR
---------------------------------------------------------------------------
95% Confidence Level, One-Day Holding Period, One-Tailed
   Period end                                                    $     0.0
   Average for the period                                              0.1
   High                                                                0.2
   Low                                                                 0.0

95% Confidence Level, Ten-Day Holding Period, Two-Tailed
   Period End                                                    $     0.6
   Average for the period                                              0.5
   High                                                                0.8
   Low                                                                 0.3

99% Confidence Level, One-Day Holding Period, Two-Tailed
   Period end                                                    $     0.2
   Average for the period                                              0.2
   High                                                                0.3
   Low                                                                 0.1
---------------------------------------------------------------------------

Credit Risk
Generation

     Generation  has credit risk  associated  with  counterparty  performance on
energy  contracts which  includes,  but is not limited to, the risk of financial
default or slow payment.  Generation  manages  counterparty  credit risk through
established policies,  including  counterparty credit limits, and in some cases,
requiring deposits and letters of credit to be posted by certain counterparties.
Generation's  counterparty  credit  limits  are  based on a scoring  model  that
considers a variety of factors,  including leverage,  liquidity,  profitability,
credit  ratings and risk  management  capabilities.  Generation has entered into
payment netting agreements or enabling agreements that allow for payment netting
with  the  majority  of its  large  counterparties,  which  reduce  Generation's
exposure to counterparty  risk by providing for the offset of amounts payable to
the counterparty  against amounts  receivable from the counterparty.  The credit
department  monitors current and forward credit exposure to  counterparties  and
their affiliates, both on an individual and an aggregate basis.




                                      142
<PAGE>

     The following table provides  information on Generation's  credit exposure,
net of collateral,  as of June 30, 2003. It further  delineates that exposure by
the  credit  rating  of  the   counterparties   and  provides  guidance  on  the
concentration of credit risk to individual  counterparties  and an indication of
the maturity of a company's credit risk by credit rating of the  counterparties.
The table below does not include  sales to  Generation's  affiliates or exposure
through Independent System Operators.


<TABLE>
<CAPTION>
                                                       Total                              Number Of   Net Exposure Of
                                                    Exposure                         Counterparties    Counterparties
                                               Before Credit   Credit          Net Greater than 10%  Greater than 10%
Rating                                            Collateral  Collateral  Exposure  of Net Exposure   of Net Exposure
---------------------------------------------------------------------------------------------------------------------
<S>                                               <C>           <C>       <C>               <C>         <C>
Investment grade                                  $    158      $  --     $   158                 3      $       81
Split rating                                            --         --          --                --              --
Non-investment grade                                    10          9           1                --              --
No external ratings
   Internally rated - investment grade                  12         --          12                 3              10
   Internally rated - non-investment grade              13          1          12                 3              12
-------------------------------------------------------------------------------------------------------------------
Total                                             $    193      $  10     $   183                 9       $      103
====================================================================================================================
</TABLE>

<TABLE>
<CAPTION>
                                                                                  Maturity of Credit Risk Exposure
                                                          --------------------------------------------------------
                                                                                          Exposure  Total Exposure
                                                              Less than               Greater than   Before Credit
Rating                                                          2 Years   2-5 Years        5 Years      Collateral
------------------------------------------------------------------------------------------------------------------
<S>                                                        <C>               <C>          <C>             <C>
Investment grade                                           $     148         $   10       $     --        $    158
Split rating                                                      --             --             --              --
Non-investment grade                                              10             --             --              10
No external ratings
   Internally rated - investment grade                            11              1             --              12
   Internally rated - non-investment grade                        13             --             --              13
------------------------------------------------------------------------------------------------------------------
Total                                                      $     182         $   11       $     --       $     193
==================================================================================================================
</TABLE>

     Generation is a counterparty to Dynegy in various energy  transactions.  In
early  July  2002,  the  credit  ratings  of  Dynegy  were  downgraded  to below
investment grade by two credit rating agencies.  As of June 30, 2003, Generation
had a net receivable  from Dynegy of  approximately  $4 million and,  consistent
with the terms of the existing credit  arrangement,  has received  collateral in
support of this  receivable.  Generation  also has credit risk  associated  with
Dynegy through  Generation's equity investment in Sithe. Sithe is a 60% owner of
the Independence  generating  station, a 1,040-MW  gas-fired  qualified facility
that has an energy-only  long-term tolling agreement with Dynegy, with a related
financial swap  arrangement.  As of June 30, 2003, Sithe had recognized an asset
on its balance  sheet  related to the fair market  value of the  financial  swap
agreement with Dynegy that is marked-to-market  under the terms of SFAS No. 133.
If Dynegy  is unable to  fulfill  the terms of this  agreement,  Sithe  would be
required to impair this financial swap asset.  Generation estimates,  as a 49.9%
owner of Sithe,  that the impairment  would result in an after-tax  reduction of
Generation's equity earnings of approximately $17 million.

     In addition to the impairment of the financial  swap asset,  if Dynegy were
unable to fulfill its  obligations  under the financial  swap  agreement and the
tolling  agreement,  Generation may incur a further  impairment  associated with
Sithe's Independence station.




                                      143
<PAGE>

     Additionally,  the  future  economic  value of  AmerGen's  purchased  power
arrangement  with  Illinois  Power  Company,  a subsidiary  of Dynegy,  could be
impacted by events related to Dynegy's financial condition.

     In connection  with ComEd's sale of assets to Midwest  Generation  prior to
the Merger,  ComEd had entered into an Agency Agreement with Midwest  Generation
and certain of Midwest Generation's  related parties (the "Guarantors")  whereby
the Guarantors assumed the benefits and liabilities of a coal purchase contract.
ComEd  remained the signatory to the coal contract,  and in connection  with the
Merger and subsequent restructuring, Generation assumed the signatory obligation
on this contract from ComEd.  Midwest  Generation's credit ratings have recently
been  downgraded  by certain  credit  rating  agencies.  In the event of Midwest
Generation and the Guarantors  non-performance under the coal purchase contract,
Generation  would be required to fulfill the purchase  commitments  which extend
through  2012.  The  contract  requires the purchase of two million tons of coal
annually,  or  specifies a minimum  payout.  Based upon current  market  prices,
Generation's  contingent  obligations  for the  contract  years 2003 to 2012 are
estimated to be approximately $81 million related to this agreement.  Generation
and ComEd have entered into other  agreements  with Midwest  Generation in which
the non-performance by Midwest Generation is currently not anticipated to result
in significant contingent obligations to Generation or ComEd.

Interest Rate Risk
ComEd

     ComEd uses a  combination  of fixed rate and  variable  rate debt to reduce
interest rate exposure.  Interest rate swaps may be used to adjust exposure when
deemed   appropriate   based  upon  market   conditions.   ComEd  also  utilizes
forward-starting interest rate swaps and treasury rate locks to lock in interest
rate levels in anticipation of future  financing.  These strategies are employed
to maintain the lowest cost of capital.  At June 30, 2003,  these  interest rate
swaps with an aggregate notional amount of $200 million, designated as cash flow
hedges,  had an aggregate  fair market value exposure of $6 million based on the
present  value of the  difference  between the contract and market rates at June
30, 2003. If these derivative  instruments had been terminated at June 30, 2003,
this  estimated  fair  value  represents  the  amount to be paid by ComEd to the
counterparties.

     The aggregate fair value exposure of the interest rate swaps  designated as
cash flow hedges that would have  resulted  from a  hypothetical  50 basis point
decrease  in the spot yield at June 30, 2003 is  estimated  to be $13 million in
the counterparties favor.

     The aggregate fair value exposure of the interest rate swaps  designated as
cash flow hedges that would have  resulted  from a  hypothetical  50 basis point
increase  in the spot  yield at June 30,  2003 is  estimated  to be less than $1
million in the counterparties favor.

     ComEd has entered into  fixed-to-floating  interest  rate swaps in order to
maintain  its  targeted   percentage  of  variable  rate  debt  associated  with
fixed-rate debt issuances in the aggregate  amount of $485 million.  At June 30,
2003,  these  interest  rate  swaps,  designated  as fair value  hedges,  had an
aggregate fair market value of $46 million based on the present value difference
between the  contract and market  rates at June 30,  2003.  If these  derivative



                                      144
<PAGE>

instruments  had been  terminated at June 30, 2003,  this  estimated  fair value
represents the amount that would be paid by the counterparties to ComEd.

     The  aggregate  fair value of the interest  rate swaps,  designated as fair
value  hedges,  that would have  resulted  from a  hypothetical  50 basis  point
decrease  in the spot yield at June 30, 2003 is  estimated  to be $53 million in
ComEd's favor.

     The  aggregate  fair value of the interest  rate swaps,  designated as fair
value  hedges,  that would have  resulted  from a  hypothetical  50 basis  point
increase  in the spot yield at June 30, 2003 is  estimated  to be $39 million in
ComEd's favor.

PECO

     In February 2003, PECO entered into forward-starting interest rate swaps in
the  aggregate  amount  of $360  million  to lock in  interest  rate  levels  in
anticipation  of future  financings.  The debt  issuances  that these swaps were
hedging  were  considered  probable in  February  2003 and closed in April 2003;
therefore,  PECO accounted for these interest rate swap  transactions as hedges.
In  connection  with PECO's April 28, 2003 issuance of $450 million in First and
Refunding Mortgage Bonds, PECO settled the swaps for net proceeds of $1 million,
which was recorded in other comprehensive income and is being amortized over the
life of the debt issuance.

     PECO has entered into interest rate swaps to manage  interest rate exposure
associated  with  the  floating  rate  series  of  transition  bonds  issued  to
securitize PECO's stranded cost recovery.  At June 30, 2003, these interest rate
swaps had an aggregate  fair market value  exposure of $17 million  based on the
present value difference between the contract and market rates at June 30, 2003.
If these  derivative  instruments  had been  terminated  at June 30, 2003,  this
estimated  fair  value  represents  the  amount  to  be  paid  by  PECO  to  the
counterparties.

     The  aggregate  fair value  exposure of the interest  rate swaps that would
have resulted from a  hypothetical  50 basis point decrease in the spot yield at
June 30, 2003 is estimated to be $18 million in the counterparties favor.

     The  aggregate  fair value  exposure of the interest  rate swaps that would
have resulted from a  hypothetical  50 basis point increase in the spot yield at
June 30, 2003 is estimated to be $15 million in the counterparties favor.

PECO  also has  interest  rate  swaps in place to  satisfy  counterparty  credit
requirements  in regards to the floating rate series of  transition  bonds which
are mirror  swaps of each  other.  These swaps are not  designated  as cash flow
hedges;  therefore,  they  are  required  to be  marked-to-market  if there is a
difference   in  their   values.   Since  these  swaps  offset  each  other,   a
mark-to-market adjustment is not expected to occur.

Generation

     Generation  uses a  combination  of fixed  rate and  variable  rate debt to
reduce  interest rate  exposure.  Generation  also uses interest rate swaps when
deemed  appropriate  to adjust  exposure  based upon  market  conditions.  These
strategies are employed to achieve a lower cost of capital.




                                      145
<PAGE>

As of  June  30,  2003,  a  hypothetical  10%  increase  in the  interest  rates
associated  with variable rate debt would not have a material  impact on pre-tax
earnings for the three and six months ended June 30, 2003.

     Under the terms of the EBG Facility, EBG is required to effectively fix the
interest  rate on 50% of borrowings  under the facility  through its maturity in
2007. As of June 30, 2003,  EBG has entered into interest rate swap  agreements,
which have  effectively  fixed the  interest  rate on $861  million of  notional
principal, or approximately 80% of borrowings outstanding under the EBG Facility
at June 30, 2003. The fair market value  exposure of these swaps,  designated as
cash flow hedges,  is $105 million.  If these  derivative  instruments  had been
terminated at June 30, 2003, this estimated fair value  represents the amount to
be paid by EBG to the counterparties.

     The aggregate fair value exposure of the interest rate swaps  designated as
cash flow hedges that would have  resulted  from a  hypothetical  50 basis point
decrease in the spot yield at June 30, 2003 is  estimated  to be $119 million in
the counterparties favor.

     The aggregate fair value exposure of the interest rate swaps  designated as
cash flow hedges that would have  resulted  from a  hypothetical  50 basis point
increase  in the spot yield at June 30, 2003 is  estimated  to be $91 million in
the counterparties favor.

     In June 2003, Generation entered into forward-starting  interest rate swaps
in the  aggregate  amount of $200  million to lock in  interest  rate  levels in
anticipation  of future  financings.  The debt  issuances  that these  swaps are
hedging are considered probable,  therefore,  Generation has accounted for these
interest rate swap transactions as hedges. At June 30, 2003, these interest rate
swaps,  designated as cash flow hedges, had an aggregate fair market value of $4
million  based on the present value of the  difference  between the contract and
market  rates  at June  30,  2003.  If  these  derivative  instruments  had been
terminated at June 30, 2003, this estimated fair value  represents the amount to
be paid by the counterparties to Generation.

     The aggregate fair value exposure of the interest rate swaps  designated as
cash flow hedges that would have  resulted  from a  hypothetical  50 basis point
decrease in the spot yield at June 30, 2003 is estimated to be $4 million in the
counterparties favor.

     The aggregate fair value of the interest rate swaps designated as cash flow
hedges that would have resulted from a  hypothetical  50 basis point increase in
the spot yield at June 30, 2003 is estimated  to be $12 million in  Generation's
favor.




                                      146
<PAGE>

Equity Price Risk
Generation

     Generation  maintains  trust funds, as required by the NRC, to fund certain
costs  of   decommissioning   its  nuclear   plants.   As  of  June  30,   2003,
decommissioning   trust  funds  are  reflected  at  fair  value  on  Exelon  and
Generation's  Consolidated  Balance  Sheets.  The mix of securities in the trust
funds is designed to provide returns to be used to fund  decommissioning  and to
compensate for inflationary  increases in decommissioning  costs.  However,  the
equity securities in the trust funds are exposed to price fluctuations in equity
markets,  and the value of fixed rate,  fixed income  securities  are exposed to
changes  in  interest  rates.   Generation   actively  monitors  the  investment
performance  of the trust funds and  periodically  reviews  asset  allocation in
accordance  with  Generation's  nuclear  decommissioning  trust fund  investment
policy.  A  hypothetical  10% increase in interest  rates and decrease in equity
prices would  result in a $175 million  reduction in the fair value of the trust
assets.


ITEM 4. CONTROLS AND PROCEDURES

Exelon

     During  the second  quarter of 2003,  Exelon's  management,  including  the
principal executive officer and principal financial officer,  evaluated Exelon's
disclosure  controls  and  procedures  related  to  the  recording,  processing,
summarization  and reporting of information in Exelon's periodic reports that it
files with the SEC. These disclosure  controls and procedures have been designed
to ensure  that (a)  material  information  relating  to Exelon,  including  its
consolidated subsidiaries, is made known to Exelon's management, including these
officers,  by other  employees  of  Exelon  and its  subsidiaries,  and (b) this
information  is recorded,  processed,  summarized,  evaluated and  reported,  as
applicable,  within the time periods specified in the SEC's rules and forms. Due
to the inherent  limitations of control systems,  not all  misstatements  may be
detected.  These  inherent  limitations  include the realities that judgments in
decision-making  can be faulty and that  breakdowns  can occur because of simple
error or mistake. Additionally, controls could be circumvented by the individual
acts of some persons or by collusion  of two or more people.  Exelon's  controls
and procedures  can only provide  reasonable,  not absolute,  assurance that the
above objectives have been met. Also,  Exelon does not control or manage certain
of its  unconsolidated  entities  and  as  such,  the  disclosure  controls  and
procedures  with  respect  to such  entities  are  more  limited  than  those it
maintains with respect to its consolidated subsidiaries.

     As of June 30, 2003, these officers  concluded that, subject to limitations
noted  above,  the design of the  disclosure  controls and  procedures  provides
reasonable  assurance that the disclosure controls and procedures can accomplish
their objectives.  Exelon continually strives to improve its disclosure controls
and procedures to enhance the quality of its financial reporting and to maintain
dynamic systems that change as conditions warrant.




                                      147
<PAGE>

     In the second  quarter of 2003,  Exelon  implemented  a new general  ledger
accounting  system.  The new general  ledger system was  implemented in order to
provide a consistent  system platform for the affiliated Exelon companies and to
enhance management reporting and analysis. This change in systems was subject to
thorough  testing and review by internal  and  external  parties both before and
after final  implementation.  Exelon continually strives to improve its internal
control over financial  reporting to provide reasonable  assurance regarding the
reliability of financial  reporting and the preparation of financial  statements
for  external  purposes  in  accordance  with  generally   accepted   accounting
principles.

ComEd

     During  the second  quarter  of 2003,  ComEd's  management,  including  the
principal executive officer and principal  financial officer,  evaluated ComEd's
disclosure  controls  and  procedures  related  to  the  recording,  processing,
summarization  and reporting of information in ComEd's  periodic reports that it
files with the SEC. These disclosure  controls and procedures have been designed
to  ensure  that (a)  material  information  relating  to ComEd,  including  its
consolidated subsidiaries, is made known to ComEd's management,  including these
officers,  by  other  employees  of  ComEd  and its  subsidiaries,  and (b) this
information  is recorded,  processed,  summarized,  evaluated and  reported,  as
applicable,  within the time periods specified in the SEC's rules and forms. Due
to the inherent  limitations of control systems,  not all  misstatements  may be
detected.  These  inherent  limitations  include the realities that judgments in
decision-making  can be faulty and that  breakdowns  can occur because of simple
error or mistake. Additionally, controls could be circumvented by the individual
acts of some persons or by collusion of two or more people. ComEd's controls and
procedures can only provide reasonable,  not absolute,  assurance that the above
objectives have been met. Also,  ComEd does not control or manage certain of its
unconsolidated entities and as such, the disclosure controls and procedures with
respect to such  entities are more limited than those it maintains  with respect
to its consolidated subsidiaries.

     As of June 30, 2003, these officers  concluded that, subject to limitations
noted  above,  the design of the  disclosure  controls and  procedures  provides
reasonable  assurance that the disclosure controls and procedures can accomplish
their objectives.  ComEd continually  strives to improve its disclosure controls
and procedures to enhance the quality of its financial reporting and to maintain
dynamic systems that change as conditions warrant.

     In the second  quarter of 2003,  ComEd  implemented  a new  general  ledger
accounting  system.  The new general  ledger system was  implemented in order to
provide a consistent  system platform for the affiliated Exelon companies and to
enhance management reporting and analysis. This change in systems was subject to
thorough  testing and review by internal  and  external  parties both before and
after final  implementation.  ComEd continually  strives to improve its internal
control over financial  reporting to provide reasonable  assurance regarding the
reliability of financial  reporting and the preparation of financial  statements
for  external  purposes  in  accordance  with  generally   accepted   accounting
principles.

PECO

     During  the  second  quarter  of 2003,  PECO's  management,  including  the
principal  executive officer and principal  financial officer,  evaluated PECO's
disclosure  controls  and




                                      148
<PAGE>

procedures related to the recording, processing,  summarization and reporting of
information  in  PECO's  periodic  reports  that it files  with  the SEC.  These
disclosure  controls  and  procedures  have been  designed  to  ensure  that (a)
material information relating to PECO, including its consolidated  subsidiaries,
is made known to PECO's management, including these officers, by other employees
of PECO and its subsidiaries,  and (b) this information is recorded,  processed,
summarized,  evaluated  and  reported,  as  applicable,  within the time periods
specified  in the SEC's  rules and forms.  Due to the  inherent  limitations  of
control  systems,  not  all  misstatements  may  be  detected.   These  inherent
limitations  include the  realities  that  judgments in  decision-making  can be
faulty  and that  breakdowns  can  occur  because  of simple  error or  mistake.
Additionally,  controls could be  circumvented  by the  individual  acts of some
persons or by collusion of two or more people.  PECO's  controls and  procedures
can only provide reasonable,  not absolute,  assurance that the above objectives
have  been  met.  Also,   PECO  does  not  control  or  manage  certain  of  its
unconsolidated entities and as such, the disclosure controls and procedures with
respect to such  entities are more limited than those it maintains  with respect
to its consolidated subsidiaries.

     As of June 30, 2003, these officers  concluded that, subject to limitations
noted  above,  the design of the  disclosure  controls and  procedures  provides
reasonable  assurance that the disclosure controls and procedures can accomplish
their objectives.  PECO continually  strives to improve its disclosure  controls
and procedures to enhance the quality of its financial reporting and to maintain
dynamic systems that change as conditions warrant.

     In the second  quarter  of 2003,  PECO  implemented  a new  general  ledger
accounting  system.  The new general  ledger system was  implemented in order to
provide a consistent  system platform for the affiliated Exelon companies and to
enhance management reporting and analysis. This change in systems was subject to
thorough  testing and review by internal  and  external  parties both before and
after final  implementation.  PECO  continually  strives to improve its internal
control over financial  reporting to provide reasonable  assurance regarding the
reliability of financial  reporting and the preparation of financial  statements
for  external  purposes  in  accordance  with  generally   accepted   accounting
principles.

Generation

     During the second quarter of 2003, Generation's  management,  including the
principal   executive  officer  and  principal   financial  officer,   evaluated
Generation's  disclosure  controls  and  procedures  related  to the  recording,
processing,  summarization and reporting of information in Generation's periodic
reports that it files with the SEC.  These  disclosure  controls and  procedures
have  been  designed  to  ensure  that  (a)  material  information  relating  to
Generation,   including  its  consolidated   subsidiaries,   is  made  known  to
Generation's  management,  including  these  officers,  by  other  employees  of
Generation  and  its  subsidiaries,   and  (b)  this  information  is  recorded,
processed,  summarized,  evaluated and reported, as applicable,  within the time
periods specified in the SEC's rules and forms. Due to the inherent  limitations
of control  systems,  not all  misstatements  may be  detected.  These  inherent
limitations  include the  realities  that  judgments in  decision-making  can be
faulty  and that  breakdowns  can  occur  because  of simple  error or  mistake.
Additionally,  controls could be  circumvented  by the  individual  acts of some
persons  or by  collusion  of two or  more  people.  Generation's  controls  and
procedures can only provide reasonable,  not absolute,  assurance that the above
objectives have been met. Also, Generation




                                      149
<PAGE>

does not control or manage certain of its  unconsolidated  entities and as such,
the disclosure  controls and  procedures  with respect to such entities are more
limited than those it maintains with respect to its consolidated subsidiaries.

     As of June 30, 2003, these officers  concluded that, subject to limitations
noted  above,  the design of the  disclosure  controls and  procedures  provides
reasonable  assurance that the disclosure controls and procedures can accomplish
their  objectives.  Generation  continually  strives to improve  its  disclosure
controls and procedures to enhance the quality of its financial reporting and to
maintain dynamic systems that change as conditions warrant.

     In the second quarter of 2003, Generation  implemented a new general ledger
accounting  system.  The new general  ledger system was  implemented in order to
provide a consistent  system platform for the affiliated Exelon companies and to
enhance management reporting and analysis. This change in systems was subject to
thorough  testing and review by internal  and  external  parties both before and
after  final  implementation.  Generation  continually  strives to  improve  its
internal  control  over  financial  reporting  to provide  reasonable  assurance
regarding  the  reliability  of  financial  reporting  and  the  preparation  of
financial statements for external purposes in accordance with generally accepted
accounting principles.


PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

ComEd

     As previously  reported in the 2002 Form 10-K and the March 2003 Form 10-Q,
three of ComEd's wholesale municipal customers had filed a complaint and request
for refund with FERC  alleging  that ComEd  failed to properly  adjust its rates
pursuant to the terms of the respective  electric service  contracts.  ComEd and
the  municipal  customers  have  executed  a  settlement  agreement  ending  the
litigation.  Under the settlement,  ComEd will pay a total of  approximately  $3
million to the three municipalities.


ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

Exelon

     On April 29, 2003, Exelon held its 2003 Annual Meeting of Shareholders.

     Proposal 1 was the election of five Class III directors to serve three-year
terms expiring in 2006. The following directors were elected:

                                    Votes For             Votes Withheld
     M. Walter D'Alessio           259,812,777              5,103,938
     Rosemarie  B. Greco           259,802,051              5,114,664
     John M. Palms                 257,952,983              6,963,732
     John W. Rogers, Jr.           256,121,360              8,795,355
     Richard L. Thomas             259,607,872              5,308,843



                                      150
<PAGE>

     Proposal  2  was  the   ratification  of   PricewaterhouseCoopers   LLP  as
independent   accountants  for  Exelon  and  its   subsidiaries  for  2003.  The
shareholders  approved the proposal with 253,274,833  votes cast for,  9,037,160
votes cast against and 2,604,722 votes abstaining.

     Proposal 3 described in the proxy  statement was a non-binding  shareholder
proposal  made by the AFL-CIO  Reserve Fund that urged the Board of Directors of
Exelon to seek shareholder  approval of any  extraordinary  pension benefits for
executives.  The  proponent  withdrew the proposal  after Exelon  agreed to make
certain changes in its compensation practices. As a result, the proposal was not
voted on at the Exelon annual  meeting.  Recognizing  shareholder  concern about
executive  compensation,  Exelon agreed that after January 1, 2004, it would not
grant additional  unearned service credits for current  executives in the Exelon
pension plans  without  shareholder  approval.  It also agreed that it would not
provide  more  than  two  years'  service  credit  under  new  change-in-control
agreements  without  shareholder  approval.  If Exelon  should need to offer new
executives  more than the pension  benefits that they would give up to come work
for Exelon, the additional pension benefits would be  performance-based  and not
guaranteed.  The  agreement  does not  affect  benefits  or  compensation  under
existing agreements,  arrangements or change-in-control  provisions. It does not
limit Exelon's rights to provide  compensation  or benefits  outside the pension
plans.

ComEd

     On May 29, 2003 ComEd held its 2003 Annual Meeting of Shareholders.

     Proposal 1 was the election of 5 directors to serve a term of one year. The
following directors were elected:

                                      Votes For             Votes Withheld
     John W. Rowe                    127,002,904                  --
     Pamela B. Strobel               127,002,904                  --
     Kenneth G. Lawrence             127,002,904                  --
     Frank M. Clark                  127,002,904                  --
     Robert S. Shapard               127,002,904                  --

     Proposal 2 was to amend the Articles of  Incorporate to add the practice of
professional engineering to the purposes for which ComEd has been organized. The
amendment  was approved with  127,002,904  votes cast for, 0 votes cast against,
and 0 votes abstaining.



                                      151
<PAGE>

PECO

     On  May  29,  2003  PECO  Energy   Company  held  its  Annual   Meeting  of
Shareholders.

     Proposal 1 was the election of 5 directors into three classes in compliance
with the Bylaws.  The three-year  terms of each class were staggered so that the
term of one class will expire at each annual  meeting.  The following  directors
were elected:

                                                 Votes For      Votes Withheld
     Class I, with term expiring in 2006:
     John W. Rowe                               170,478,507            --

     Class II, with term expiring in 2005:
     Pamela B. Strobel                          170,478,507            --
     Kenneth G. Lawrence                        170,478,507            --

     Class III, with term expiring in 2004:
     Frank M. Clark                             170,478,507            --
     Robert S. Shapard                          170,478,507            --


ITEM 5. OTHER INFORMATION

ComEd

     As  previously  reported  in  the  2002  Form  10-K,  in  July  2002,  FERC
conditionally  approved  ComEd's  decision to join PJM. On April 1, 2003,  ComEd
received approval from FERC to transfer control of ComEd's  transmission  assets
to PJM.  FERC also  accepted for filing the PJM tariff as amended to reflect the
inclusion of ComEd and other new members,  subject to a compliance filing, which
was made on May 1, 2003,  and to hearing  on  certain  issues.  On June 2, 2003,
ComEd began receiving electric  transmission  reservation  services from PJM and
transferred  control of its Open  Access  Same Time  Information  System to PJM.
ComEd expects to transfer  functional control of its transmission  assets to PJM
and to integrate fully into PJM's energy market structures on November 1, 2003.

PECO

     As previously  reported in the 2002 Form 10-K and the March 2003 Form 10-Q,
on August 15, 2002, the International  Brotherhood of Electrical  Workers (IBEW)
filed a petition  with the National  Labor  Relations  Board (NLRB) to conduct a
unionization  vote of certain of PECO's  employees.  On May 21,  2003,  the PECO
union  election  was held and a majority of PECO  workers  voted  against  union
representation.  The  results of the  election  have not been  certified  due to
pending challenges and objections.

     As  previously  reported in the 2002 Form 10-K,  the PUC's  Final  Electric
Restructuring Order established MSTs to promote competition. On May 1, 2003, the
PUC approved the residential customer plan filed by PECO in February 2003. Under
the  plan,  a total of  375,000  residential  customers  may be  transferred  to
alternative   electric   generation   suppliers  in  December  2003.   Customers
transferred will have the right to return to PECO at any time.





                                      152
<PAGE>

Generation

     As previously  reported in the 2002 Form 10-K,  on April 9, 2003,  the IBEW
filed a petition  with the NLRB to  represent  all  production  and  maintenance
employees  in   Generation's   fossil  and   hydroelectric   operations  in  the
Mid-Atlantic  operating  group.  These  approximate  300  employees had not been
covered by a collective bargaining agreement.  . Pursuant to an election held on
June 18, 2003, the employees voted to become represented by the IBEW.


ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits:

              4.1 -        Indenture to Subordinated Debt Securities dated as of
                           June 24, 2003 between PECO Energy Company, as Issuer,
                           and Wachovia Bank National Association, as Trustee.
              4.2 -        Preferred Securities Guarantee Agreement between PECO
                           Energy  Company,  as  Guarantor,  and Wachovia  Trust
                           Company,  National Association,  as Trustee, dated as
                           of June 24, 2003.
              4.3 -        PECO Energy  Capital  Trust IV Amended  and  Restated
                           Declaration  of Trust among PECO Energy  Company,  as
                           Sponsor,    Wachovia    Trust    Company,    National
                           Association,   as  Delaware   Trustee  and   Property
                           Trustee, and J. Barry Mitchell, George R. Shicora and
                           Charles S. Walls as Administrative  Trustees dated as
                           of June 24, 2003.

Certifications  Pursuant to Rule  13a-14(a) and 15d-14(a) of the  Securities and
Exchange Act of 1934 as to the  Quarterly  Report on Form 10-Q for the quarterly
period ended June 30, 2003 filed by the  following  officers  for the  following
companies:
--------------------------------------------------------------------------------
31.1  -    Filed by John W. Rowe for Exelon Corporation
31.2  -    Filed by Robert S. Shapard for Exelon Corporation
31.3  -    Filed by Michael B. Bemis for Commonwealth Edison Company
31.4  -    Filed by Robert S. Shapard for Commonwealth Edison Company
31.5  -    Filed by Michael B. Bemis for PECO Energy Company
31.6  -    Filed by Robert S. Shapard for PECO Energy Company
31.7  -    Filed by Oliver D. Kingsley Jr. for Exelon Generation Company, LLC
31.8  -    Filed by Robert S. Shapard for Exelon Generation Company, LLC
--------------------------------------------------------------------------------

Certifications  Pursuant to Section 1350 of Chapter 63 of Title 18 United States
Code (Sarbanes - Oxley Act of 2002) as to the Quarterly  Report on Form 10-Q for
the quarterly period ended June 30, 2003 filed by the following officers for the
following companies:
--------------------------------------------------------------------------------
32.1  -    Filed by John W. Rowe for Exelon Corporation
32.2  -    Filed by Robert S. Shapard for Exelon Corporation
32.3  -    Filed by Michael B. Bemis for Commonwealth Edison Company
32.4  -    Filed by Robert S. Shapard for Commonwealth Edison Company
32.5  -    Filed by Michael B. Bemis for PECO Energy Company
32.6  -    Filed by Robert S. Shapard for PECO Energy Company
32.7  -    Filed by Oliver D. Kingsley Jr. for Exelon Generation Company, LLC
32.8  -    Filed by Robert S. Shapard for Exelon Generation Company, LLC
--------------------------------------------------------------------------------



                                      153
<PAGE>

(b) Reports on Form 8-K:

Exelon,  ComEd,  PECO and/or Generation filed Current Reports on Form 8-K during
the three months ended June 30, 2003 regarding the following items:

<TABLE>
<CAPTION>
Date of Earliest
Event Reported            Description of Item Reported
----------------------------------------------------------------------------------------------
<S>                       <C>
April 3, 2003             "ITEM 9.  REGULATION FD DISCLOSURE"  filed for Exelon,  ComEd,  PECO
                          and Generation  regarding a presentation  by John W. Rowe,  Chairman
                          and CEO, at the  Berenson & Company and The Williams  Capital  Group
                          Midwest  Utilities  Seminar.  The  exhibits  include the slides used
                          during the presentation.

April 7, 2003             "ITEM 5. OTHER  EVENTS"  filed by ComEd  regarding  the  issuance of
                          $395 million in First Mortgage Bonds.

April 28, 2003            "ITEM 9. REGULATION FD DISCLOSURE"  filed under Item 9 in compliance
                          with Item 12 for Exelon,  ComEd,  PECO and Generation  regarding the
                          first quarter 2003 earnings  release and items discussed  during the
                          earnings  conference  call.  Also  included  as an  exhibit  to this
                          report  was  a new  release  regarding  the  "Exelon  Way"  business
                          model.

May 2, 2003               "ITEM 5.  OTHER  EVENTS"  filed  for  Exelon  regarding  Richard  H.
                          Glanton's  acceptance  of the  position  of Senior  Vice  President,
                          Corporate  Development and his relinquishment of his directorship on
                          the Exelon Board.

May 7, 2003               "ITEM 5.  OTHER  EVENTS"  filed  for  Exelon,  PECO  and  Generation
                          announcing that the U.S. Nuclear  Regulatory  Commission  approved a
                          20-year  extension of the  operating  licenses for Exelon  Nuclear's
                          Peach Bottom Atomic Power Station.

May 20, 2003              "ITEM 9.  REGULATION  FD  DISCLOSURE"  filed for Exelon  regarding a
                          presentation  by Robert S.  Shapard,  Executive  Vice  President and
                          CFO.  The exhibit includes the slides used during the presentation.

May 29, 2003              "ITEM 5. OTHER  EVENTS" filed for Exelon and  Generation  announcing
                          the issuance of a call notice for the  remaining  50.1%  interest in
                          Sithe Energies, Inc.

June 2, 2003              "ITEM 5. OTHER EVENTS" filed for Exelon and  Generation  regarding a
                          request  for an  amendment  to the  Exelon  Boston




                                      154
<PAGE>
                          Generating, LLC credit facility and the construction of the Mystic 8
                          and 9 and Fore River generating units.

June 2, 2003              "ITEM 5. OTHER  EVENTS"  filed for Exelon and  Generation  regarding
                          the approval of an amendment to the Exelon  Boston Generating,  LLC
                          credit facility.

June 11, 2003             "ITEM 9.  REGULATION FD DISCLOSURE"  filed for Exelon,  ComEd,  PECO
                          and  Generation  regarding  a  presentation  by Robert  S.  Shapard,
                          Executive  Vice  President and CFO. The exhibits  include the slides
                          and handouts used during the presentation.

June 13, 2003             "ITEM 5. OTHER EVENTS"  filed for Exelon  regarding the dismissal of
                          a class action lawsuit.

June 18, 2003             "ITEM 5. OTHER EVENTS"  filed for Exelon  announcing an agreement to
                          sell certain businesses of its subsidiary InfraSource, Inc.

June 18, 2003             "ITEM  5.  OTHER   EVENTS"  filed  for  Exelon,   ComEd,   PECO  and
                          Generation  regarding the sale of certain businesses of InfraSource,
                          Inc.

June 25, 2003             "ITEM 5. OTHER  EVENTS"  filed for  Exelon,  ComEd,  and  Generation
                          regarding  the  exercise  of  Generation's   call  option  under  an
                          existing purchase power agreement with Midwest Generation, LLC.
----------------------------------------------------------------------------------------------
</TABLE>




                                             155
<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.

                               EXELON CORPORATION

/s/ John W. Rowe                            /s/ Robert S. Shapard
----------------------------------          -----------------------------------
JOHN W. ROWE                                ROBERT S. SHAPARD
Chairman and                                Executive Vice President and Chief
Chief Executive Officer                     Financial Officer
(Principal Executive Officer)               (Principal Financial Officer)

/s/ Matthew F. Hilzinger
----------------------------------
MATTHEW F. HILZINGER
Vice President and Corporate Controller
(Principal Accounting Officer)

July 30, 2003

--------------------------------------------------------------------------------

     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.

                           COMMONWEALTH EDISON COMPANY

/s/ Michael B. Bemis                        /s/ Robert S. Shapard
----------------------------------          -----------------------------------
MICHAEL B. BEMIS                            ROBERT S. SHAPARD
President, Exelon Energy Delivery           Executive Vice President and Chief
(Principal Executive Officer)               Financial Officer, Exelon
                                            (Principal Financial Officer)

/s/ Duane M. DesParte
----------------------------------
DUANE M. DESPARTE
Vice President and Controller, Exelon Energy Delivery
(Principal Accounting Officer)

July 30, 2003




                                      156
<PAGE>

--------------------------------------------------------------------------------

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

                               PECO ENERGY COMPANY

/s/ Michael B. Bemis                        /s/ Robert S. Shapard
----------------------------------          -----------------------------------
MICHAEL B. BEMIS                            ROBERT S. SHAPARD
President, Exelon Energy Delivery           Executive Vice President and Chief
(Principal Executive Officer)               Financial Officer, Exelon
                                            (Principal Financial Officer)

/s/ Duane M. DesParte
----------------------------------
DUANE M. DESPARTE
Vice President and Controller, Exelon Energy Delivery
(Principal Accounting Officer)

July 30, 2003

--------------------------------------------------------------------------------

     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.

                         EXELON GENERATION COMPANY, LLC

/s/ Oliver D. Kingsley Jr.                  /s/ Robert S. Shapard
----------------------------------          -----------------------------------
OLIVER D. KINGSLEY JR.                      ROBERT S. SHAPARD
Chief Executive Officer and                 Executive Vice President and Chief
President                                   Financial Officer, Exelon
(Principal Executive Officer)               (Principal Financial Officer)

/s/ Thomas Weir III
----------------------------------
THOMAS WEIR III
Vice President and Controller
(Principal Accounting Officer)

July 30, 2003



                                      157