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 September 30, 2003
                                       OR

            [ ]         TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
                        SECURITIES EXCHANGE ACT OF 1934
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<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
September 30, 2003 was:
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<CAPTION>


<S>                                                              <C>
Exelon Corporation Common Stock, without par value               327,021,190
Commonwealth Edison Company Common Stock, $12.50 par value       127,016,483
PECO Energy Company Common Stock, without par value              170,478,507
Exelon Generation Company, LLC                                   not applicable

</TABLE>


     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>


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<CAPTION>


                                TABLE OF CONTENTS


                                                                                                                   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                                                                           71
                      Exelon Corporation                                                                             76
                      Commonwealth Edison Company                                                                   109
                      PECO Energy Company                                                                           124
                      Exelon Generation Company, LLC                                                                140

      ITEM 3.   QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK                                           157
      ITEM 4.   CONTROLS AND PROCEDURES                                                                             169

      PART II.  OTHER INFORMATION                                                                                   172
      ITEM 1.   LEGAL PROCEEDINGS                                                                                   172
      ITEM 3.   DEFAULTS UPON SENIOR SECURITIES                                                                     172
      ITEM 5.   OTHER INFORMATION                                                                                   173
      ITEM 6.   EXHIBITS AND REPORTS ON FORM 8-K                                                                    174

     SIGNATURES                                                                                                     176



</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's website at www.exeloncorp.com.



                                       3
<PAGE>



                          PART I. FINANCIAL INFORMATION

                          ITEM 1. FINANCIAL STATEMENTS






                                       4
<PAGE>


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

                                 EXELON CORPORATION AND SUBSIDIARY COMPANIES
                       CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
                                              (Unaudited)
                                                                            Three Months Ended             Nine Months Ended
                                                                            ------------------             -----------------
                                                                               September 30,                 September 30,
                                                                               ------------                  -------------
   (in millions, except per share data)                                    2003             2002             2003             2002
----------------------------------------------------------------------------------------------------------------------------------

<S>                                                                      <C>              <C>              <C>              <C>
   OPERATING REVENUES                                                  $  4,441         $  4,370         $ 12,236        $ 11,245

   OPERATING EXPENSES
       Purchased power                                                    1,179            1,233            2,765           2,543
       Purchased power from unconsolidated affiliate                        133              104              310             220
       Fuel                                                                 551              373            1,908           1,233
       Impairment of Exelon Boston Generating, LLC long-lived assets        945             --                945            --
       Operating and maintenance                                          1,226            1,114            3,438           3,252
       Depreciation and amortization                                        293              345              842           1,012
       Taxes other than income                                              131              201              489             568
---------------------------------------------------------------------------------------------------------------------------------
            Total operating expenses                                      4,458            3,370           10,697           8,828
---------------------------------------------------------------------------------------------------------------------------------
   OPERATING INCOME (LOSS)                                                  (17)           1,000            1,539           2,417
---------------------------------------------------------------------------------------------------------------------------------
   OTHER INCOME AND DEDUCTIONS
       Interest expense                                                    (213)            (249)            (652)           (739)
       Interest expense to affiliates                                        (4)            --                 (9)           --
       Distributions on preferred securities of subsidiaries                 (8)             (11)             (30)            (34)
       Equity in earnings of unconsolidated affiliates                       49               92               82             114
       Other, net                                                           (21)              16             (153)            239
---------------------------------------------------------------------------------------------------------------------------------
            Total other income and deductions                              (197)            (152)            (762)           (420)
---------------------------------------------------------------------------------------------------------------------------------
   INCOME (LOSS) BEFORE INCOME TAXES AND CUMULATIVE
     EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES                            (214)             848              777           1,997
   INCOME TAXES                                                            (112)             297              258             724
---------------------------------------------------------------------------------------------------------------------------------
   INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGES IN
     ACCOUNTING PRINCIPLES                                                 (102)             551              519           1,273
   CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING
     PRINCIPLES (net of income taxes of $69 and $(90) for the nine
     months ended September 30, 2003 and 2002, respectively)               --               --                112            (230)
---------------------------------------------------------------------------------------------------------------------------------
   NET INCOME (LOSS)                                                       (102)             551              631           1,043
---------------------------------------------------------------------------------------------------------------------------------

   OTHER COMPREHENSIVE INCOME (LOSS) (net of income taxes)
         Minimum pension liability                                            9             --                  9            --
         Cash flow hedge adjustment                                         142              (32)              58            (103)
         Foreign currency translation adjustment                           --               --                  2            --
         Unrealized gain (loss) on marketable securities                      5              (73)               3            (158)
         SFAS No. 143 transition adjustment                                --               --                168            --
         Interest in other comprehensive income (loss)
            of unconsolidated affiliates                                      1              (20)               9             (21)
---------------------------------------------------------------------------------------------------------------------------------
            Total other comprehensive income (loss)                         157             (125)             249            (282)
---------------------------------------------------------------------------------------------------------------------------------

   TOTAL COMPREHENSIVE INCOME                                          $     55         $    426         $    880        $    761
==================================================================================================================================

   AVERAGE SHARES OF COMMON STOCK OUTSTANDING - Basic                       326              323              325             322
==================================================================================================================================
   AVERAGE SHARES OF COMMON STOCK OUTSTANDING - Diluted                     326              324              328             324
==================================================================================================================================

   EARNINGS (LOSS) PER AVERAGE COMMON SHARE:
       BASIC:
       Income (loss) before cumulative effect of changes in
         accounting principles                                         $  (0.31)        $   1.71         $   1.60        $   3.95
       Cumulative effect of changes in accounting principles               --               --               0.34           (0.71)
---------------------------------------------------------------------------------------------------------------------------------
       Net income (loss)                                               $  (0.31)        $   1.71         $   1.94        $   3.24
==================================================================================================================================

       DILUTED:
       Income (loss) before cumulative effect of changes in
         accounting principles                                         $  (0.31)        $   1.70         $   1.59        $   3.93
       Cumulative effect of changes in accounting principles               --               --               0.34           (0.71)
---------------------------------------------------------------------------------------------------------------------------------
       Net income (loss)                                               $  (0.31)        $   1.70         $   1.93        $   3.22
==================================================================================================================================

   DIVIDENDS PER COMMON SHARE                                          $   0.50         $   0.44         $   1.42        $   1.32
==================================================================================================================================
     See Condensed Combined Notes to Consolidated Financial Statements

</TABLE>



                                       5
<PAGE>

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<CAPTION>


                                   EXELON CORPORATION AND SUBSIDIARY COMPANIES
                                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                                                   (Unaudited)
                                                                                          Nine Months Ended September 30,
                                                                                        -------------------------------
     (in millions)                                                                               2003              2002
-----------------------------------------------------------------------------------------------------------------------
     CASH FLOWS FROM OPERATING ACTIVITIES
<S>                                                                                              <C>          <C>
         Net income                                                                              $   631      $   1,043
         Adjustments to reconcile net income to net cash flows provided by
         operating activities:
              Depreciation, amortization and accretion, including nuclear fuel                     1,290          1,284
              Cumulative effect of changes in accounting principles (net of income taxes)           (112)           230
              Gain on sale of investment                                                              --           (199)
              Provision for uncollectible accounts                                                    72            107
              Deferred income taxes                                                                 (363)           293
              Equity in earnings of unconsolidated affiliates                                        (82)          (114)
              Impairment of investments                                                              295             46
              Impairment of long-lived assets                                                        950             --
              Employee severance-related costs                                                       152             --
              Pension and non-pension postretirement curtailment costs                                26             --
              Net realized (gains) losses on nuclear decommissioning trust funds                      (9)            32
              Other operating activities                                                              91             56
              Changes in assets and liabilities:
                Accounts receivable                                                                  (19)          (358)
                Inventories                                                                          (55)           (25)
                Accounts payable, accrued expenses and other current liabilities                      50              1
                Changes in payables and receivables from unconsolidated affiliates                    18             46
                Other current assets                                                                (100)            68
                Pension and non-pension postretirement benefits obligations                         (241)            22
                Other noncurrent assets and liabilities                                              (41)           131
-----------------------------------------------------------------------------------------------------------------------
     Net cash flows provided by operating activities                                               2,553          2,663
-----------------------------------------------------------------------------------------------------------------------

     CASH FLOWS FROM INVESTING ACTIVITIES
         Capital expenditures                                                                     (1,501)        (1,534)
         Proceeds from liquidated damages                                                             92             --
         Proceeds from nuclear decommissioning trust funds                                         1,880          1,184
         Investment in nuclear decommissioning trust funds                                        (2,043)        (1,330)
         Note receivable from unconsolidated affiliate                                                35            (42)
         Proceeds from sale of investments                                                           186            287
         Acquisition of generating plants                                                             --           (443)
         Other investing activities                                                                   50             19
-----------------------------------------------------------------------------------------------------------------------
     Net cash flows used in investing activities                                                  (1,301)        (1,859)
-----------------------------------------------------------------------------------------------------------------------

     CASH FLOWS FROM FINANCING ACTIVITIES
         Issuance of long-term debt                                                                2,105            956
         Retirement of long-term debt                                                             (2,075)        (1,946)
         Change in short-term debt                                                                  (599)           428
         Issuance of long-term debt to affiliate                                                     103             --
         Issuance of mandatorily redeemable preferred securities of subsidiaries                     200             --
         Retirement of mandatorily redeemable preferred securities of subsidiaries                  (250)           (18)
         Retirement of preferred stock of subsidiaries                                               (50)            --
         Dividends paid on common stock                                                             (461)          (420)
         Payment on acquisition note payable to Sithe Energies, Inc.                                (210)            --
         Proceeds from employee stock plans                                                          139             64
         Contribution from minority interest of consolidated subsidiary                               --             43
         Change in restricted cash                                                                    78             81
         Other financing activities                                                                  (85)           (16)
-----------------------------------------------------------------------------------------------------------------------
     Net cash flows used in financing activities                                                  (1,105)          (828)
-----------------------------------------------------------------------------------------------------------------------

     INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS                                                147            (24)

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

     CASH AND CASH EQUIVALENTS INCLUDING CASH CLASSIFIED AS HELD FOR SALE                        $   616     $      461
     CASH CLASSIFIED AS HELD FOR SALE ON THE CONSOLIDATED BALANCE SHEET                              (12)            --
-----------------------------------------------------------------------------------------------------------------------
     CASH AND CASH EQUIVALENTS AT END OF PERIOD                                                  $   604     $      461
=======================================================================================================================
       See Condensed Combined Notes to Consolidated Financial Statements
</TABLE>



                                       6
<PAGE>

<TABLE>
<CAPTION>


                                   EXELON CORPORATION AND SUBSIDIARY COMPANIES
                                           CONSOLIDATED BALANCE SHEETS
                                                   (Unaudited)


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

     CURRENT ASSETS
<S>                                                                                          <C>                <C>
         Cash and cash equivalents                                                           $    604           $   469
         Restricted cash                                                                          318               396
         Accounts receivable, net
              Customer                                                                          1,952             2,076
              Other                                                                               270               284
         Receivable from unconsolidated affiliate                                                 ---                39
         Inventories, at average cost
              Fossil fuel                                                                         198               175
              Materials and supplies                                                              289               306
         Other                                                                                    429               380
         Assets held for sale                                                                     109                --
-----------------------------------------------------------------------------------------------------------------------
              Total current assets                                                              4,169             4,125
-----------------------------------------------------------------------------------------------------------------------

     PROPERTY, PLANT AND EQUIPMENT, NET                                                        19,476            17,126

     DEFERRED DEBITS AND OTHER ASSETS
         Regulatory assets                                                                      5,304             5,993
         Nuclear decommissioning trust funds                                                    3,404             3,053
         Investments                                                                            1,198             1,403
         Goodwill                                                                               4,734             4,992
         Other                                                                                    859               793
-----------------------------------------------------------------------------------------------------------------------
              Total deferred debits and other assets                                           15,499            16,234
-----------------------------------------------------------------------------------------------------------------------

     TOTAL ASSETS                                                                            $ 39,144        $   37,485
=======================================================================================================================


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


                                       7
<PAGE>

<TABLE>
<CAPTION>



                                   EXELON CORPORATION AND SUBSIDIARY COMPANIES
                                           CONSOLIDATED BALANCE SHEETS
                                                   (Unaudited)


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

     CURRENT LIABILITIES
<S>                                                                                          <C>                <C>
         Notes payable                                                                       $     82           $   681
         Note payable to unconsolidated affiliate                                                 326               534
         Long-term debt due within one year                                                     2,067             1,402
         Accounts payable                                                                       1,692             1,607
         Accrued expenses                                                                       1,242             1,354
         Other                                                                                    287               296
         Liabilities held for sale                                                                 57                --
-----------------------------------------------------------------------------------------------------------------------
              Total current liabilities                                                         5,753             5,874
-----------------------------------------------------------------------------------------------------------------------

     LONG-TERM DEBT                                                                            12,468            13,127
     LONG-TERM DEBT TO AFFILIATE                                                                  103                --
     MANDATORILY REDEEMABLE PREFERRED SECURITIES                                                  422                --

     DEFERRED CREDITS AND OTHER LIABILITIES
         Deferred income taxes                                                                  3,798             3,702
         Unamortized investment tax credits                                                       291               301
         Nuclear decommissioning liability for retired plants                                      --             1,395
         Asset retirement obligation                                                            2,481                --
         Pension obligation                                                                     1,609             1,959
         Non-pension postretirement benefits obligation                                         1,033               877
         Spent nuclear fuel obligation                                                            865               858
         Regulatory liabilities                                                                   880                --
         Other                                                                                  1,026               978
-----------------------------------------------------------------------------------------------------------------------
              Total deferred credits and other liabilities                                     11,983            10,070
-----------------------------------------------------------------------------------------------------------------------
              Total liabilities                                                                30,729            29,071
-----------------------------------------------------------------------------------------------------------------------

     COMMITMENTS AND CONTINGENCIES

     MINORITY INTEREST OF CONSOLIDATED SUBSIDIARIES                                                 1                77

     PREFERRED SECURITIES OF SUBSIDIARIES                                                          87               595

     SHAREHOLDERS' EQUITY
         Common stock                                                                           7,226             7,059
         Deferred compensation                                                                     --                (1)
         Retained earnings                                                                      2,210             2,042
         Accumulated other comprehensive income (loss)                                         (1,109)           (1,358)
-----------------------------------------------------------------------------------------------------------------------
              Total shareholders' equity                                                        8,327             7,742
-----------------------------------------------------------------------------------------------------------------------

     TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY                                              $ 39,144        $   37,485
=======================================================================================================================


                        See Condensed Combined Notes to Consolidated Financial Statements

</TABLE>


                                       8
<PAGE>

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<CAPTION>



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

                              COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
                           CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
                                                   (Unaudited)


                                                                           Three Months Ended         Nine Months Ended
                                                                           ------------------         -----------------
                                                                                September 30,             September 30,
                                                                                -------------             -------------
     (in millions)                                                          2003         2002         2003         2002
-----------------------------------------------------------------------------------------------------------------------
<S>                                                                    <C>            <C>          <C>          <C>
     OPERATING REVENUES
         Operating revenues                                            $   1,717      $ 1,912      $ 4,473      $ 4,685
         Operating revenues from affiliates                                   20           26           49           49
-----------------------------------------------------------------------------------------------------------------------
              Total operating revenues                                     1,737        1,938        4,522        4,734
-----------------------------------------------------------------------------------------------------------------------

     OPERATING EXPENSES
         Purchased power                                                       6            8           17           20
         Purchased power from affiliate                                      885          967        1,984        2,046
         Operating and maintenance                                           259          234          683          620
         Operating and maintenance from affiliates                            40           33           98          104
         Depreciation and amortization                                        97          129          287          397
         Taxes other than income                                              87           77          235          223
-----------------------------------------------------------------------------------------------------------------------
              Total operating expenses                                     1,374        1,448        3,304        3,410
-----------------------------------------------------------------------------------------------------------------------

     OPERATING INCOME                                                        363          490        1,218        1,324
-----------------------------------------------------------------------------------------------------------------------

     OTHER INCOME AND DEDUCTIONS
         Interest expense                                                   (107)        (122)        (322)        (374)
         Distributions on mandatorily redeemable preferred securities         (6)          (7)         (20)         (22)
         Interest income from affiliates                                       6            8           20           23
         Other, net                                                            9           (8)          28            6
-----------------------------------------------------------------------------------------------------------------------
              Total other income and deductions                              (98)        (129)        (294)        (367)
-----------------------------------------------------------------------------------------------------------------------

     INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT
       OF A CHANGE IN ACCOUNTING PRINCIPLE                                   265          361          924          957

     INCOME TAXES                                                            102          146          365          381
-----------------------------------------------------------------------------------------------------------------------

     INCOME BEFORE CUMULATIVE EFFECT OF A CHANGE IN
       ACCOUNTING  PRINCIPLE                                                 163          215          559          576

     CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING
       PRINCIPLE (net of income taxes of $0)                                  --           --            5           --
-----------------------------------------------------------------------------------------------------------------------
     NET INCOME                                                              163          215          564          576
-----------------------------------------------------------------------------------------------------------------------

     OTHER COMPREHENSIVE INCOME (LOSS) (net of income taxes)
             Cash flow hedge adjustment                                        3          (19)          31          (25)
           Unrealized gain (loss) on marketable securities                     2           (1)           3           (3)
           Foreign currency translation adjustment                            --           --            2           --
-----------------------------------------------------------------------------------------------------------------------
              Total other comprehensive income (loss)                          5          (20)          36          (28)
-----------------------------------------------------------------------------------------------------------------------

     TOTAL COMPREHENSIVE INCOME                                        $     168      $   195      $   600        $ 548
=======================================================================================================================

                        See Condensed Combined Notes to Consolidated Financial Statements


                                       9
<PAGE>

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

                                                                                         Nine Months Ended September 30,
                                                                                        -------------------------------
     (in millions)                                                                               2003              2002
-----------------------------------------------------------------------------------------------------------------------
     CASH FLOWS FROM OPERATING ACTIVITIES
         Net income                                                                          $    564           $   576
         Adjustments to reconcile net income to net cash flows provided by
         operating activities:
              Depreciation and amortization                                                       287               397
              Cumulative effect of a change in accounting principle (net of income taxes)          (5)               --
              Gain on sale of investments                                                          (3)               --
              Provision for uncollectible accounts                                                 31                29
              Deferred income taxes                                                                92                92
              Employee severance-related costs                                                     58                --
              Pension and non-pension postretirement curtailment costs                              2                --
              Other operating activities                                                           49                76
              Changes in assets and liabilities:
                Accounts receivable                                                               (55)             (198)
                Inventories                                                                         7                (4)
                Accounts payable, accrued expenses and other current liabilities                 (102)               52
                Changes in receivables and payables to affiliates                                 (45)              449
                Other current assets                                                              (12)               (2)
                Pension and non-pension postretirement benefits obligations                      (112)               15
                Other noncurrent assets and liabilities                                           (14)                9
-----------------------------------------------------------------------------------------------------------------------
     Net cash flows provided by operating activities                                              742             1,491
-----------------------------------------------------------------------------------------------------------------------

     CASH FLOWS FROM INVESTING ACTIVITIES
         Capital expenditures                                                                    (537)             (549)
         Investment in affiliate money pool                                                      (147)               --
         Notes receivable from affiliates                                                         213                14
         Proceeds from sale of investments                                                          5                --
         Other investing activities                                                                16                 7
-----------------------------------------------------------------------------------------------------------------------
     Net cash flows used in investing activities                                                 (450)             (528)
-----------------------------------------------------------------------------------------------------------------------

     CASH FLOWS FROM FINANCING ACTIVITIES
         Issuance of long-term debt                                                             1,427               701
         Retirement of long-term debt                                                          (1,139)           (1,365)
         Issuance of mandatorily redeemable preferred securities                                  200                --
         Retirement of mandatorily redeemable preferred securities                               (200)               --
         Change in short-term debt                                                                (71)               94
         Dividends paid on common stock                                                          (305)             (353)
         Change in restricted cash                                                                (17)              (37)
         Settlement of cash flow hedges                                                           (45)              (10)
         Other financing activities                                                               (36)               --
-----------------------------------------------------------------------------------------------------------------------
     Net cash flows used in financing activities                                                 (186)             (970)
-----------------------------------------------------------------------------------------------------------------------

     INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS                                             106                (7)


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


     CASH AND CASH EQUIVALENTS AT END OF PERIOD                                              $    122            $   16
=======================================================================================================================

     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)



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

     CURRENT ASSETS
<S>                                                                                          <C>                 <C>
         Cash and cash equivalents                                                           $    122            $   16
         Restricted cash                                                                           82                65
         Accounts receivable, net
              Customer                                                                            818               782
              Other                                                                                60                72
         Inventories, at average cost                                                              50                65
         Deferred income taxes                                                                     19                20
         Receivables from affiliates                                                              151                15
         Other                                                                                     26                14
-----------------------------------------------------------------------------------------------------------------------
              Total current assets                                                              1,328             1,049
-----------------------------------------------------------------------------------------------------------------------

     PROPERTY, PLANT AND EQUIPMENT, NET                                                         8,039             7,756

     DEFERRED DEBITS AND OTHER ASSETS
         Regulatory assets                                                                         --               447
         Investments                                                                               36                42
         Goodwill                                                                               4,711             4,916
         Receivables from affiliates                                                            2,228             1,300
         Prepaid pension asset                                                                     48                --
         Other                                                                                    389               320
-----------------------------------------------------------------------------------------------------------------------
         Total deferred debits and other assets                                                 7,412             7,025
-----------------------------------------------------------------------------------------------------------------------

     TOTAL ASSETS                                                                            $ 16,779        $   15,830
=======================================================================================================================


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


                                       11
<PAGE>

<TABLE>
<CAPTION>


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


                                                                                         September 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                                                       519               698
         Accounts payable                                                                         207               201
         Accrued expenses                                                                         465               538
         Payables to affiliates                                                                   186               416
         Customer deposits                                                                         78                81
         Other                                                                                     13                18
-----------------------------------------------------------------------------------------------------------------------
              Total current liabilities                                                         1,468             2,023
-----------------------------------------------------------------------------------------------------------------------

     LONG-TERM DEBT                                                                             5,755             5,268

     MANDATORILY REDEEMABLE PREFERRED SECURITIES                                                  344                --

     DEFERRED CREDITS AND OTHER LIABILITIES
          Deferred income taxes                                                                 1,776             1,650
          Unamortized investment tax credits                                                       49                51
          Pension obligation                                                                       --                91
          Non-pension postretirement benefits obligation                                          187               138
          Payables to affiliates                                                                   39               224
          Regulatory liabilities                                                                  880                --
          Other                                                                                   332               297
-----------------------------------------------------------------------------------------------------------------------
              Total deferred credits and other liabilities                                      3,263             2,451
-----------------------------------------------------------------------------------------------------------------------
              Total liabilities                                                                10,830             9,742
-----------------------------------------------------------------------------------------------------------------------

     COMMITMENTS AND CONTINGENCIES

     MANDATORILY REDEEMABLE PREFERRED SECURITIES                                                   --               330

     SHAREHOLDERS' EQUITY
         Common stock                                                                           1,588             1,588
         Preference stock                                                                           7                 7
         Other paid in capital                                                                  4,029             4,239
         Receivable from parent                                                                  (509)             (615)
         Retained earnings                                                                        836               577
         Accumulated other comprehensive income (loss)                                             (2)              (38)
-----------------------------------------------------------------------------------------------------------------------
              Total shareholders' equity                                                        5,949             5,758
-----------------------------------------------------------------------------------------------------------------------

     TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY                                              $ 16,779        $   15,830
=======================================================================================================================


                        See Condensed Combined Notes to Consolidated Financial Statements

</TABLE>
                                       12
<PAGE>




<TABLE>
<CAPTION>

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

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

                                                                           Three Months Ended         Nine Months Ended
                                                                           ------------------         -----------------
                                                                                September 30,             September 30,
                                                                                -------------             -------------
     (in millions)                                                          2003         2002         2003         2002
-----------------------------------------------------------------------------------------------------------------------
     OPERATING REVENUES
<S>                                                                    <C>            <C>          <C>          <C>
         Operating revenues                                            $   1,146      $ 1,221      $ 3,319      $ 3,230
         Operating revenues from affiliates                                    3            3            9            9
-----------------------------------------------------------------------------------------------------------------------
              Total operating revenues                                     1,149        1,224        3,328        3,239
-----------------------------------------------------------------------------------------------------------------------

     OPERATING EXPENSES
         Purchased power                                                      61           68          189          175
         Purchased power from affiliate                                      421          441        1,101        1,090
         Fuel                                                                 28           40          285          228
         Operating and maintenance                                           178          125          414          350
         Operating and maintenance from affiliates                            14           15           39           57
         Depreciation and amortization                                       134          127          370          348
         Taxes other than income                                              12           85          123          207
-----------------------------------------------------------------------------------------------------------------------
              Total operating expenses                                       848          901        2,521        2,455
-----------------------------------------------------------------------------------------------------------------------

     OPERATING INCOME                                                        301          323          807          784
-----------------------------------------------------------------------------------------------------------------------

     OTHER INCOME AND DEDUCTIONS
         Interest expense                                                    (73)         (93)        (241)        (280)
         Interest expense to affiliate                                        (2)          --           (2)          --
         Distributions on mandatorily redeemable preferred securities         (1)          (2)          (6)          (7)
         Other, net                                                          (10)           5           --            7
-----------------------------------------------------------------------------------------------------------------------
              Total other income and deductions                              (86)         (90)        (249)        (280)
-----------------------------------------------------------------------------------------------------------------------

     INCOME BEFORE INCOME TAXES                                              215          233          558          504

     INCOME TAXES                                                             74           76          193          166
-----------------------------------------------------------------------------------------------------------------------

     NET INCOME                                                              141          157          365          338
         Preferred stock dividends                                            (1)          (2)          (4)          (6)
-----------------------------------------------------------------------------------------------------------------------
     NET INCOME ON COMMON STOCK                                        $     140      $   155      $   361        $ 332
=======================================================================================================================


     OTHER COMPREHENSIVE INCOME (LOSS)  (net of income taxes)
         Net income                                                    $     141      $   157      $   365        $ 338
         Other comprehensive income (loss) (net of income taxes):
           Cash flow hedge adjustment                                          2           (5)           2          (10)
           Unrealized gain (loss) on marketable securities                     1           (1)           1           --
-----------------------------------------------------------------------------------------------------------------------
              Total other comprehensive income (loss)                          3           (6)           3          (10)
-----------------------------------------------------------------------------------------------------------------------

     TOTAL COMPREHENSIVE INCOME                                        $     144      $   151      $   368        $ 328
=======================================================================================================================


        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)

                                                                                            Nine Months Ended September 30,
                                                                                            --------------------------------
     (in millions)                                                                               2003              2002
-----------------------------------------------------------------------------------------------------------------------
     CASH FLOWS FROM OPERATING ACTIVITIES
<S>                                                                                          <C>                <C>
         Net income                                                                          $    365           $   338
         Adjustments to reconcile net income to net cash flows provided by
         operating activities:
              Depreciation and amortization                                                       370               348
              Provision for uncollectible accounts                                                 38                48
              Deferred income taxes                                                               (76)              (64)
              Employee severance-related costs                                                     25                --
              Pension and non-pension postretirement curtailment costs                             16                --
              Other operating activities                                                           (2)               (2)
              Changes in assets and liabilities:
                Accounts receivable                                                                25               (69)
                Changes in receivables and payables to affiliates                                  68               (27)
                Inventories                                                                       (44)               (8)
                Accounts payable, accrued expenses and other current liabilities                   39              (107)
                Prepaid taxes                                                                     (46)              (49)
                Deferred energy costs                                                             (33)               50
                Other current assets                                                               (4)               (2)
                Pension and non-pension postretirement benefits obligations                        17                 8
                Other noncurrent assets and liabilities                                            (1)                9
-----------------------------------------------------------------------------------------------------------------------
     Net cash flows provided by operating activities                                              757               473
-----------------------------------------------------------------------------------------------------------------------


     CASH FLOWS FROM INVESTING ACTIVITIES
         Capital expenditures                                                                    (191)             (180)
         Other investing activities                                                                (2)                3
-----------------------------------------------------------------------------------------------------------------------
     Net cash flows used in investing activities                                                 (193)             (177)
-----------------------------------------------------------------------------------------------------------------------


     CASH FLOWS FROM FINANCING ACTIVITIES
         Issuance of long-term debt                                                               450               225
         Retirement of long-term debt                                                            (709)             (571)
         Issuance of long-term debt to affiliate                                                  103                --
         Retirement of mandatorily redeemable preferred securities                                (50)              (19)
         Retirement of preferred stock                                                            (50)               --
         Change in short-term debt                                                               (188)              274
         Dividends paid on preferred and common stock                                            (248)             (261)
         Contribution from parent                                                                  17                30
         Change in restricted cash                                                                132               113
         Other financing activities                                                                (2)               (5)
-----------------------------------------------------------------------------------------------------------------------
     Net cash flows used in financing activities                                                 (545)             (214)
-----------------------------------------------------------------------------------------------------------------------


     INCREASE IN CASH AND CASH EQUIVALENTS                                                         19                82


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


     CASH AND CASH EQUIVALENTS AT END OF PERIOD                                               $    82           $   114
=======================================================================================================================


        See Condensed Combined Notes to Consolidated Financial Statements


                                       14
<PAGE>


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


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

     CURRENT ASSETS
         Cash and cash equivalents                                                           $     82            $   63
         Restricted cash                                                                          199               331
         Accounts receivable, net
              Customer                                                                            326               379
              Other                                                                                32                39
         Inventories, at average cost
              Fossil fuel                                                                         111                67
              Materials and supplies                                                                8                 8
         Deferred energy costs                                                                     64                31
         Prepaid taxes                                                                             47                 1
         Other                                                                                     11                 8
-----------------------------------------------------------------------------------------------------------------------
              Total current assets                                                                880               927
-----------------------------------------------------------------------------------------------------------------------

     PROPERTY, PLANT AND EQUIPMENT, NET                                                         4,239             4,159

     DEFERRED DEBITS AND OTHER ASSETS
         Regulatory assets                                                                      5,304             5,546
         Investments                                                                               23                19
         Prepaid pension asset                                                                     62                41
         Other                                                                                     22                28
-----------------------------------------------------------------------------------------------------------------------
              Total deferred debits and other assets                                            5,411             5,634
-----------------------------------------------------------------------------------------------------------------------

     TOTAL ASSETS                                                                            $ 10,530        $   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)



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

     CURRENT LIABILITIES
<S>                                                                                          <C>                <C>
         Notes payable                                                                       $     12           $   200
         Payables to affiliates                                                                   142               170
         Long-term debt due within one year                                                       292               689
         Accounts payable                                                                          66                87
         Accrued expenses                                                                         402               332
         Deferred income taxes                                                                     27                27
         Other                                                                                     36                33
-----------------------------------------------------------------------------------------------------------------------
              Total current liabilities                                                           977             1,538
-----------------------------------------------------------------------------------------------------------------------

     LONG-TERM DEBT                                                                             5,087             4,951
     LONG-TERM DEBT TO AFFILIATE                                                                  103                --
     MANDATORILY REDEEMABLE PREFERRED SECURITIES                                                   78                --

     DEFERRED CREDITS AND OTHER LIABILITIES
         Deferred income taxes                                                                  2,855             2,903
         Unamortized investment tax credits                                                        22                24
         Non-pension postretirement benefits obligation                                           317               251
         Payable to affiliate                                                                       7                --
         Other                                                                                    140               164
-----------------------------------------------------------------------------------------------------------------------
              Total deferred credits and other liabilities                                      3,341             3,342
-----------------------------------------------------------------------------------------------------------------------
              Total liabilities                                                                 9,586             9,831
-----------------------------------------------------------------------------------------------------------------------

     COMMITMENTS AND CONTINGENCIES

     MANDATORILY REDEEMABLE PREFERRED SECURITIES                                                   --               128

     SHAREHOLDERS' EQUITY
         Common stock                                                                           1,993             1,976
         Receivable from parent                                                                (1,661)           (1,758)
         Preferred stock                                                                           87               137
         Retained earnings                                                                        517               401
         Accumulated other comprehensive income                                                     8                 5
-----------------------------------------------------------------------------------------------------------------------
              Total shareholders' equity                                                          944               761
-----------------------------------------------------------------------------------------------------------------------

     TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY                                              $ 10,530        $   10,720
=======================================================================================================================


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


                                       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,        Nine Months Ended,
                                                                          ------------------         -----------------
                                                                              September 30,             September 30,
                                                                          ------------------         -----------------
     (in millions)                                                          2003         2002         2003         2002
-----------------------------------------------------------------------------------------------------------------------
     OPERATING REVENUES
<S>                                                                    <C>            <C>          <C>          <C>
         Operating revenues                                            $   1,180      $   750      $ 3,055      $ 1,924
         Operating revenues from affiliates                                1,357        1,463        3,246        3,309
-----------------------------------------------------------------------------------------------------------------------
              Total operating revenues                                     2,537        2,213        6,301        5,233
-----------------------------------------------------------------------------------------------------------------------

     OPERATING EXPENSES
         Purchased power                                                   1,096        1,147        2,531        2,334
         Purchased power from affiliates                                     144          110          350          247
         Fuel                                                                449          273        1,156          706
         Impairment of Exelon Boston Generating, LLC long-lived assets       945           --          945           --
         Operating and maintenance                                           476          351        1,337        1,098
         Operating and maintenance from affiliates                            54           40          136          136
         Depreciation and amortization                                        51           68          142          197
         Taxes other than income                                              28           37          115          126
-----------------------------------------------------------------------------------------------------------------------
              Total operating expenses                                     3,243        2,026        6,712        4,844
-----------------------------------------------------------------------------------------------------------------------

     OPERATING INCOME (LOSS)                                                (706)         187         (411)         389
-----------------------------------------------------------------------------------------------------------------------

     OTHER INCOME AND DEDUCTIONS
         Interest expense                                                    (22)         (22)         (52)         (48)
         Interest expense - affiliates                                        (3)          (1)         (11)          (3)
         Equity in earnings of unconsolidated affiliates                      53           87           90          119
         Other, net                                                          (30)          14         (164)          54
-----------------------------------------------------------------------------------------------------------------------
              Total other income and deductions                               (2)          78         (137)         122
-----------------------------------------------------------------------------------------------------------------------

     INCOME (LOSS) BEFORE INCOME TAXES AND CUMULATIVE
       EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES                           (708)         265         (548)         511
     INCOME TAXES                                                           (280)         102         (209)         198
-----------------------------------------------------------------------------------------------------------------------

     INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGES IN
       ACCOUNTING PRINCIPLES                                                (428)         163         (339)         313

     CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING
       PRINCIPLES (net of income taxes of $70 and $9 for the nine
        months ended September 30, 2003 and 2002, respectively)               --           --          108           13
-----------------------------------------------------------------------------------------------------------------------

     NET INCOME (LOSS)                                                      (428)         163         (231)         326
-----------------------------------------------------------------------------------------------------------------------

       OTHER COMPREHENSIVE INCOME (LOSS) (net of income taxes)
           Cash flow hedge adjustment                                        147          (11)          30          (79)
           Unrealized gain (loss) on marketable securities                     1          (69)          (1)        (151)
           SFAS No. 143 transition adjustment                                 --           --          168           --
           Interest in other comprehensive income (loss)
               of unconsolidated affiliates                                    1          (20)           9          (21)
-----------------------------------------------------------------------------------------------------------------------
              Total other comprehensive income (loss)                        149         (100)         206         (251)
-----------------------------------------------------------------------------------------------------------------------

     TOTAL COMPREHENSIVE INCOME (LOSS)                                 $    (279)     $    63      $   (25)        $ 75
=======================================================================================================================

</TABLE>

        See Condensed Combined Notes to Consolidated Financial Statements


                                       17
<PAGE>

<TABLE>
<CAPTION>


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

                                                                                        Nine Months Ended September 30,
                                                                                        -------------------------------
     (in millions)                                                                               2003              2002
-----------------------------------------------------------------------------------------------------------------------
     CASH FLOWS FROM OPERATING ACTIVITIES
<S>                                                                                          <C>                <C>
         Net income (loss)                                                                   $   (231)          $   326
         Adjustments to reconcile net income (loss) to net cash flows provided
         by operating activities:
              Depreciation, amortization and accretion, including nuclear fuel                    594               475
              Cumulative effect of changes in accounting principles (net of income taxes)        (108)              (13)
              Provision for uncollectible accounts                                                  1                20
              Deferred income taxes                                                              (393)              246
              Equity in earnings of unconsolidated affiliates                                     (90)             (119)
              Impairment of investment                                                            255                --
              Impairment of long-lived assets                                                     950                --
              Employee severance-related costs                                                     45                --
              Pension and non-pension postretirement curtailment costs                              6                --
              Net realized (gains) losses on nuclear decommissioning trust funds                   (9)               32
              Other operating activities                                                            6                33
              Changes in assets and liabilities:
                Accounts receivable                                                              (124)              (90)
                Changes in receivables and payables to affiliates, net                            254              (278)
                Inventories                                                                       (10)              (16)
                Accounts payable, accrued expenses and other current liabilities                  100               153
                Other current assets                                                              (16)              (95)
                Pension and non-pension postretirement benefits obligations                       (91)               (3)
                Other noncurrent assets and liabilities                                             2               100
-----------------------------------------------------------------------------------------------------------------------
     Net cash flows provided by operating activities                                            1,141               771
-----------------------------------------------------------------------------------------------------------------------

     CASH FLOWS FROM INVESTING ACTIVITIES
         Capital expenditures                                                                    (733)             (715)
         Proceeds from liquidated damages                                                          92                --
         Proceeds from nuclear decommissioning trust funds                                      1,880             1,184
         Investment in nuclear decommissioning trust funds                                     (2,043)           (1,330)
         Notes receivable from affiliates                                                          20               (42)
         Acquisition of generating plants                                                          --              (443)
         Other investing activities                                                                12                 3
-----------------------------------------------------------------------------------------------------------------------
     Net cash flows used in investing activities                                                 (772)           (1,343)
-----------------------------------------------------------------------------------------------------------------------

     CASH FLOWS FROM FINANCING ACTIVITIES
         Issuance of long-term debt                                                               211                30
         Retirement of long-term debt                                                              (4)               (4)
         Payment on acquisition note payable to Sithe Energies, Inc.                             (210)               --
         Proceeds (repayment) of affiliate money pool funds                                      (178)              348
         Distribution to member                                                                  (116)              (30)
         Contribution from minority interest of consolidated subsidiary                            --                43
         Change in restricted cash                                                                (25)               --
         Other financing activities                                                                (2)               --
-----------------------------------------------------------------------------------------------------------------------
     Net cash flows (used in) provided by financing activities                                   (324)              387
-----------------------------------------------------------------------------------------------------------------------

     INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS                                              45              (185)

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

     CASH AND CASH EQUIVALENTS AT END OF PERIOD                                               $   103            $   39
=======================================================================================================================

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

                            See Condensed Combined Notes to Consolidated Financial Statements

</TABLE>


                                       18
<PAGE>

<TABLE>
<CAPTION>


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


<S>                                                                                          <C>
                                                                                            September 30,      December 31,
     (in millions)                                                                               2003              2002
-----------------------------------------------------------------------------------------------------------------------
     ASSETS

     CURRENT ASSETS
         Cash and cash equivalents                                                           $    103            $   58
         Restricted cash                                                                           37                --
         Accounts receivable, net
              Customer                                                                            644               587
              Other                                                                                92                57
         Receivables from affiliates                                                              313               594
         Inventories, at average cost
              Fossil fuel                                                                          72                97
              Materials and supplies                                                              229               217
         Deferred income taxes                                                                      2                 7
         Other                                                                                    192               188
-----------------------------------------------------------------------------------------------------------------------
              Total current assets                                                              1,684             1,805
-----------------------------------------------------------------------------------------------------------------------

     PROPERTY, PLANT AND EQUIPMENT, NET                                                         7,010             4,800

     DEFERRED DEBITS AND OTHER ASSETS
         Nuclear decommissioning trust funds                                                    3,404             3,053
         Investments                                                                              487               657
         Receivable from affiliate                                                                 41               220
         Deferred income taxes                                                                    292               271
         Prepaid pension asset                                                                     98                --
         Other                                                                                    224               201
-----------------------------------------------------------------------------------------------------------------------
              Total deferred debits and other assets                                            4,546             4,402
-----------------------------------------------------------------------------------------------------------------------

     TOTAL ASSETS                                                                            $ 13,240        $   11,007
=======================================================================================================================

                            See Condensed Combined Notes to Consolidated Financial Statements

</TABLE>


                                       19
<PAGE>

<TABLE>
<CAPTION>


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



                                                                                        September 30,      December 31,
     (in millions)                                                                               2003              2002
<S>                                                                                          <C>                  <C>
-----------------------------------------------------------------------------------------------------------------------
     LIABILITIES AND MEMBER'S EQUITY

     CURRENT LIABILITIES
         Long-term debt due within one year                                                  $  1,251             $   5
         Accounts payable                                                                       1,287             1,126
         Payables to affiliates                                                                    67                10
         Notes payable to affiliates                                                              477               863
         Accrued expenses                                                                         397               482
         Other                                                                                     90               108
-----------------------------------------------------------------------------------------------------------------------
              Total current liabilities                                                         3,569             2,594
-----------------------------------------------------------------------------------------------------------------------

     LONG-TERM DEBT                                                                             1,110             2,132

     DEFERRED CREDITS AND OTHER LIABILITIES
         Unamortized investment tax credits                                                       220               226
         Nuclear decommissioning liability for retired plants                                      --             1,395
         Asset retirement obligation                                                            2,479                --
         Pension obligation                                                                        --                37
         Non-pension postretirement benefits obligation                                           480               410
         Spent nuclear fuel obligation                                                            865               858
         Payable to affiliate                                                                   1,144                --
         Other                                                                                    421               402
-----------------------------------------------------------------------------------------------------------------------
              Total deferred credits and other liabilities                                      5,609             3,328
-----------------------------------------------------------------------------------------------------------------------
              Total liabilities                                                                10,288             8,054
-----------------------------------------------------------------------------------------------------------------------

     COMMITMENTS AND CONTINGENCIES

     MINORITY INTEREST OF CONSOLIDATED SUBSIDIARY                                                  --                54

     MEMBER'S EQUITY
         Membership interest                                                                    2,490             2,296
         Undistributed earnings                                                                   577               924
         Accumulated other comprehensive income (loss)                                           (115)             (321)
-----------------------------------------------------------------------------------------------------------------------
              Total member's equity                                                             2,952             2,899
-----------------------------------------------------------------------------------------------------------------------
     TOTAL LIABILITIES AND MEMBER'S EQUITY                                                    $13,240        $   11,007
=======================================================================================================================

        See Condensed Combined Notes to Consolidated Financial Statements


</TABLE>

                                       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  consolidated   financial  statements  of  Exelon  Corporation
     (Exelon),  Commonwealth Edison Company (ComEd),  PECO Energy Company (PECO)
     and Exelon  Generation  Company,  LLC (Generation)  include the accounts of
     their  majority-owned  subsidiaries  after the  elimination of intercompany
     transactions. Investments and joint ventures in which a 20% to 50% interest
     is owned and a significant influence is exerted are accounted for under the
     equity method of accounting.  PECO Energy Capital Trust IV (PECO Trust IV),
     which was created in May 2003,  is a wholly owned  financing  subsidiary of
     PECO. As of July 1, 2003,  PECO Trust IV is no longer  consolidated  within
     the  financial  statements of Exelon or PECO.  See Note 2 - New  Accounting
     Principles   and   Accounting   Changes  for  further   discussion  of  the
     deconsolidation of this entity.

              The accompanying consolidated financial statements as of September
     30, 2003 and for the three and nine months then ended are  unaudited,  but,
     in the opinions of the managements of Exelon,  ComEd,  PECO and 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 Reports
     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

              Financial Accounting Standards Board (FASB) 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



                                       21
<PAGE>

     lives  projected to be from 2029 through 2056.  These nuclear  plants,  the
     decommissioning  obligation 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 in trust accounts of $3,404
     million and $3,053  million as of September 30, 2003 and December 31, 2002,
     respectively.  Generation  anticipates  that all  trust  fund  assets  will
     ultimately be used to decommission Generation's nuclear plants.

              After  considering  interpretations  of the transitional  guidance
     included in SFAS No. 143,  Exelon  recorded  income of $112 million (net of
     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, net of income taxes, were 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.
     Exelon's  accretion  expense of the ARO for the three and nine months ended
     September  30,  2003  was  $39  million  and  $117  million,  respectively.
     Generation's  accretion  expense  for  the  three  and  nine  months  ended
     September  30,  2003 was $39 million and $116  million,  respectively.  The
     following  table  provides a  reconciliation  of the AROs  reflected on the
     balance sheet at December 31, 2002 and September 30, 2003:

<TABLE>
<CAPTION>
                                                                          Generation            Exelon
     ----------------------------------------------------------------------------------------------------
<S>                                                                         <C>              <C>
     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
     ----------------------------------------------------------------------------------------------------
       Asset retirement obligation at January 1, 2003                          2,363             2,366
       Reclassification of Enterprises ARO to liabilities held for sale
            during the third quarter of 2003                                      --                (2)
       Accretion expense for nine months ended September 30, 2003                116               117
     ----------------------------------------------------------------------------------------------------
     Asset retirement obligation at September 30, 2003                       $ 2,479           $ 2,481
     ====================================================================================================
</TABLE>



                                       22
<PAGE>

              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 the  decommissioning  obligation at
     the time of adoption of SFAS No. 143.

              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 nine months  ended  September  30, 2002
     adjusted as if SFAS No. 143 had been applied effective January 1, 2002.

<TABLE>
<CAPTION>
                                                                  Three Months Ended                  Nine Months Ended
                                                                  September 30, 2002                 September 30, 2002
     -----------------------------------------------------------------------------------------------------------------------
<S>                                                                        <C>                                <C>
     Reported income before cumulative effect
         of changes in accounting principles                               $     551                          $   1,273
     Adjustment as if SFAS No. 143 had been applied
          effective January 1, 2002                                                8                                 28
     -----------------------------------------------------------------------------------------------------------------------
     Adjusted income before cumulative effect
         of changes in accounting principles                               $     559                          $   1,301
     =======================================================================================================================

                                                                  Three Months Ended                  Nine Months Ended
                                                                  September 30, 2002                 September 30, 2002
     -----------------------------------------------------------------------------------------------------------------------
     Reported net income                                                   $     551                          $   1,043
     Adjustment as if SFAS No. 143 had been applied
          effective January 1, 2002:
              Adjustment to income before cumulative effect
               of changes in accounting principles                                 8                                 28
              Cumulative effect of changes in accounting principles               --                                132
     -----------------------------------------------------------------------------------------------------------------------
     Adjusted net income                                                   $     559                          $   1,203
     =======================================================================================================================

</TABLE>






                                       23
<PAGE>

<TABLE>
<CAPTION>
                                                                                  Three Months Ended September 30, 2002
                                                                                  -------------------------------------
     Basic earnings per common share:                                        Reported        Adjustment (1)    Adjusted
     ------------------------------------------------------------------------------------------------------------------
<S>                                                                        <C>               <C>              <C>
     Income before cumulative effect
         of changes in accounting principles                               $     1.71        $    0.02        $    1.73
     Net income                                                            $     1.71        $    0.02        $    1.73
     ------------------------------------------------------------------------------------------------------------------

                                                                                  Three Months Ended September 30, 2002
                                                                                  -------------------------------------
     Diluted earnings per common share:                                      Reported       Adjustment  (1)    Adjusted
     ------------------------------------------------------------------------------------------------------------------
     Income before cumulative effect
         of changes in accounting principles                               $     1.70        $    0.02        $    1.72
     Net income                                                            $     1.70        $    0.02        $    1.72
     ------------------------------------------------------------------------------------------------------------------
     (1)   The adjustment represents the earnings impact as if SFAS No. 143 had been applied effective January 1, 2002.


                                                                                   Nine Months Ended September 30, 2002
                                                                                  -------------------------------------
     Basic earnings per common share:                                        Reported        Adjustment (1)    Adjusted
     ------------------------------------------------------------------------------------------------------------------
     Income before cumulative effect
         of changes in accounting principles                               $     3.95        $    0.09        $    4.04
     Net income                                                            $     3.24        $    0.50        $    3.74
     ------------------------------------------------------------------------------------------------------------------

                                                                                   Nine Months Ended September 30, 2002
                                                                                  -------------------------------------
     Diluted earnings per common share:                                      Reported       Adjustment  (1)    Adjusted
     ------------------------------------------------------------------------------------------------------------------
     Income before cumulative effect
         of changes in accounting principles                               $     3.93        $    0.09        $    4.02
     Net income                                                            $     3.22        $    0.49        $    3.71
     ------------------------------------------------------------------------------------------------------------------
     (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 September 30,
     2003, the regulatory liability and corresponding receivable from Generation





                                       24
<PAGE>

     totaled $1,144  million.  Exelon  believes that all of the  decommissioning
     assets,  including  up to $73  million  of annual  collections  from  ComEd
     ratepayers  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 September 30, 2003, the regulatory  asset and  corresponding  payable to
     Generation   totaled  $7  million.   Exelon   believes   that  all  of  the
     decommissioning  assets,  including $29 million of annual  collections from
     PECO ratepayers which will increase to approximately  $33 million beginning
     in 2004, 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. See Note 5 - Regulatory Issues for more information  regarding
     the annual collections from PECO.

              Prior to the  adoption of SFAS No. 143,  Generation's  accumulated
     depreciation  included  $2,845  million  for  decommissioning   liabilities
     related to active nuclear  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 ARO related to former
     PECO plants in  accordance  with SFAS No. 143.  The ARC is being  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  concluded  that had
     SFAS No. 143 been in effect, ComEd would not have recorded an impairment of
     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, 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 recorded a SFAS No. 143 transition  adjustment
     to accumulated  other  comprehensive  income to reclassify  $168 million of





                                       25
<PAGE>

     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 nine months ended  September 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                  Nine Months Ended
     ComEd                                                        September 30, 2002                 September 30, 2002
     ------------------------------------------------------------------------------------------------------------------
<S>                                                                        <C>                                <C>
     Reported net income                                                   $     215                          $     576
     Adjustment as if SFAS No. 143 had been applied
          effective January 1, 2002:
              Cumulative effect of changes in accounting principles               --                                  5
     ------------------------------------------------------------------------------------------------------------------
     Adjusted net income                                                   $     215                          $     581
     ==================================================================================================================

                                                                  Three Months Ended                  Nine Months Ended
     Generation                                                   September 30, 2002                 September 30, 2002
     ------------------------------------------------------------------------------------------------------------------
     Reported income before cumulative effect
         of changes in accounting principles                               $     163                          $     313
     Adjustment as if SFAS No. 143 had been applied
          effective January 1, 2002                                                8                                 28
     ------------------------------------------------------------------------------------------------------------------
     Adjusted income before cumulative effect
         of changes in accounting principles                               $     171                          $     341
     ==================================================================================================================

                                                                  Three Months Ended                  Nine Months Ended
     Generation                                                   September 30, 2002                 September 30, 2002
     ------------------------------------------------------------------------------------------------------------------
     Reported net income                                                   $     163                          $     326
     Adjustment as if SFAS No. 143 had been applied
          effective January 1, 2002:
              Adjustment to income before cumulative effect
               of changes in accounting principles                                 8                                 28
              Cumulative effect of changes in accounting principles               --                                128
     ------------------------------------------------------------------------------------------------------------------
     Adjusted net income                                                   $     171                          $     482
     ==================================================================================================================
</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





                                       26
<PAGE>

     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 the 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  from   ratepayers  of
     decommissioning  costs  of its  former  plants,  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.  AmerGen is a
     50% owned subsidiary of Generation.

     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 were as follows:

     ---------------------------------------------------------------------------
     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)
     ===========================================================================

              At September  30, 2003,  Exelon had goodwill of $4,734  million of
     which $4,711 million relates to ComEd and the remaining goodwill relates to
     Enterprises'  Reporting Units.  Consistent with SFAS No. 142, the remaining


                                       27
<PAGE>

     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. See Note 3 - Acquisitions, Dispositions and Retirements for a
     discussion  of an  impairment  of  Enterprises'  goodwill  related  to  the
     InfraSource Reporting Unit recorded in the second quarter of 2003.

     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 not
     affected by the adoption SFAS No. 146.

     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 nine months ended  September 30, 2003 are reflected
     in Note 9 - Commitments and Contingencies.






                                       28
<PAGE>

     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 nine
     months ended September 30, 2003 and 2002:

<TABLE>
<CAPTION>
     Exelon
                                                                                       Three Months Ended September 30,
                                                                                       --------------------------------
                                                                                             2003                  2002
     ------------------------------------------------------------------------------------------------------------------
<S>                                                                                     <C>                   <C>
     Net income (loss) - as reported                                                    $    (102)            $     551
     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 (loss)                                                        $    (107)            $     543
     ==================================================================================================================
     Earnings (loss) per share:
        Basic - as reported                                                             $   (0.31)            $    1.71
        Basic - pro forma                                                               $   (0.33)            $    1.68

        Diluted - as reported                                                           $   (0.31)            $    1.70
        Diluted - pro forma                                                             $   (0.33)            $    1.67
     ------------------------------------------------------------------------------------------------------------------

                                                                                        Nine Months Ended September 30,
                                                                                        -------------------------------
                                                                                             2003                  2002
     ------------------------------------------------------------------------------------------------------------------
     Net income - as reported                                                           $     631             $   1,043
     Deduct: Total stock-based compensation expense
        determined under fair value based method for all
        awards, net of income taxes                                                           (16)                  (25)
     ------------------------------------------------------------------------------------------------------------------
     Pro forma net income                                                               $     615             $   1,018
     ==================================================================================================================
     Earnings per share:
        Basic - as reported                                                             $    1.94             $    3.24
        Basic - pro forma                                                               $    1.89             $    3.16

        Diluted - as reported                                                           $    1.93             $    3.22
        Diluted - pro forma                                                             $    1.88             $    3.14
     ------------------------------------------------------------------------------------------------------------------




                                       29
<PAGE>

     ComEd
                                                                                       Three Months Ended September 30,
                                                                                       --------------------------------
                                                                                             2003                  2002
     -------------------------------------------------------------------------------------------------------------------
     Net income - as reported                                                           $     163             $     215
     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                                                               $     162             $     212
     ===================================================================================================================

                                                                                        Nine Months Ended September 30,
                                                                                        -------------------------------
                                                                                             2003                  2002
     -------------------------------------------------------------------------------------------------------------------
     Net income - as reported                                                           $     564             $     576
     Deduct: Total stock-based compensation expense
        determined under fair value based method for all
        awards, net of income taxes                                                            (4)                  (10)
     -------------------------------------------------------------------------------------------------------------------
     Pro forma net income                                                               $     560             $     566
     ===================================================================================================================

     PECO
                                                                                       Three Months Ended September 30,
                                                                                       --------------------------------
                                                                                             2003                  2002
     -------------------------------------------------------------------------------------------------------------------
     Net income on common stock- as reported                                            $     140             $     155
     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                                               $     139             $     152
     ===================================================================================================================

                                                                                        Nine Months Ended September 30,
                                                                                        -------------------------------
                                                                                             2003                  2002
     -------------------------------------------------------------------------------------------------------------------
     Net income on common stock- as reported                                            $     361             $     332
     Deduct: Total stock-based compensation expense
        determined under fair value based method for all
        awards, net of income taxes                                                            (2)                  (10)
     -------------------------------------------------------------------------------------------------------------------
     Pro forma net income on common stock                                               $     359             $     322
     ===================================================================================================================

     Generation
                                                                                       Three Months Ended September 30,
                                                                                       --------------------------------
                                                                                             2003                  2002
     -------------------------------------------------------------------------------------------------------------------
     Net income (loss) - as reported                                                    $    (428)            $     163
     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 (loss)                                                        $    (431)            $     159
     ===================================================================================================================

                                                                                        Nine Months Ended September 30,
                                                                                        -------------------------------
                                                                                             2003                  2002
     -------------------------------------------------------------------------------------------------------------------
     Net income (loss) - as reported                                                    $    (231)            $     326
     Deduct: Total stock-based compensation expense
        determined under fair value based method for all
        awards, net of income taxes                                                            (8)                  (11)
     -------------------------------------------------------------------------------------------------------------------
     Pro forma net income (loss)                                                        $    (239)            $     315
     ===================================================================================================================
</TABLE>




                                       30
<PAGE>

     FIN No. 46

              In January  2003,  the FASB issued FIN No. 46,  "Consolidation  of
     Variable Interest  Entities" (FIN No. 46), which addresses the requirements
     for   consolidating   certain  variable   interest   entities  and  applies
     immediately to variable  interest  entities created after January 31, 2003.
     FIN No.  46,  as  amended  by FASB  Staff  Position  (FSP)  No.  FIN  46-6,
     "Effective Date of FASB  Interpretation  No. 46,  Consolidation of Variable
     Interest  Entities,"  requires  Exelon  to  consolidate  variable  interest
     entities, created prior to February 1, 2003, as of December 31, 2003.

              As of July 1,  2003,  PECO  Trust  IV,  a wholly  owned  financing
     subsidiary of PECO created in May 2003, was no longer  consolidated  within
     the financial  statements  of Exelon or PECO pursuant to the  provisions of
     FIN No. 46. PECO recognized  equity in earnings of less than $1 million for
     the  three  and nine  months  ended  September  30,  2003  related  to this
     unconsolidated subsidiary. Amounts of $103 million owed to PECO Trust IV by
     PECO are recorded as long-term  debt to affiliate  within the  Consolidated
     Balance  Sheets,  and interest  owed to this entity is recorded as interest
     expense to  affiliate  within  the  Consolidated  Statements  of Income and
     Comprehensive Income. This change in presentation had no significant impact
     on net income or the balance  sheet of Exelon or PECO.  Prior  periods have
     not been restated.

              Based on management's  interpretation of the current provisions of
     FIN No. 46, it is  reasonably  possible  that the  remaining  wholly  owned
     financing  trusts  and  limited  partnerships  of ComEd  and  PECO  will be
     required to be  deconsolidated  as of  December  31,  2003.  This change in
     presentation is anticipated to have no significant  impact on net income or
     the balance sheet of Exelon, ComEd or PECO.

              Based on management's  interpretation of the current provisions of
     FIN No. 46, it is reasonably  possible  that  Generation  will  consolidate
     Sithe  Energies,  Inc.  (Sithe)  and  AmerGen  as  of  December  31,  2003.
     Generation  is a 49.9% owner of Sithe and has  accounted for this entity as
     an  unconsolidated  equity  investment.   Sithe  owns  and  operates  power
     generating  facilities.  AmerGen is a joint venture between  Generation and
     British Energy,  Inc.  (British Energy) and owns and operates three nuclear
     units, the Clinton Power Station (Clinton),  Three Mile Island Unit 1 (TMI)
     and Oyster Creek  Generating  Station  (Oyster  Creek).  Refer to Note 17 -
     Unconsolidated  Equity  Investments in Generation's  Form 10-K for the year
     ended December 31, 2002 and Note 4 - Unconsolidated Investments and Note 15
     - Subsequent  Events in this Form 10-Q for further  information  related to
     Generation's  investments  in Sithe and AmerGen and  Exelon's  agreement to
     purchase British Energy's interest in AmerGen.  Also, see Note 13 - Related
     Party  Transactions  for a description  of the activity  between Exelon and
     Sithe and Exelon and AmerGen.

     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




                                       31
<PAGE>

     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 was 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 were to 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 had 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.

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

              As of  July 1,  2003,  ComEd  and  PECO  reclassified  mandatorily
     redeemable  preferred securities of subsidiaries from equity to liabilities
     of $344 million and $78 million, respectively. There was no impact from the
     adoption of this  standard  on the  Consolidated  Statements  of Income and
     Comprehensive Income of ComEd and PECO.

              During  June  2003,  PECO  issued  $103  million  of  subordinated
     debentures to PECO Trust IV in  connection  with the issuance by PECO Trust
     IV of $100 million of preferred  securities  (see Note 12 - Long-Term  Debt
     and Preferred  Securities).  These  preferred  securities  were recorded as
     liabilities  of PECO as of June 30, 2003 in  accordance  with SFAS No. 150.
     Effective July 1, 2003, PECO Trust IV was deconsolidated from the financial
     statements of PECO in conjunction with the adoption of FIN No. 46. The $103
     million  of  subordinated  debentures  issued by PECO to PECO  Trust IV was
     recorded as long-term  debt to affiliate  within the  Consolidated  Balance
     Sheets.

              As  previously   reported  in  Generation's   Capital  Commitments
    footnotes to the financial statements in the 2002 Form 10-K,  Generation has
    a 73% interest in the Southeast  Chicago Project,  LLC (Southeast  Chicago),
    which owns a peaking facility in Chicago.  Southeast Chicago is obligated to
    redeem  approximately  $52  million  over the next 19 years to a party,  not
    affiliated with Generation, that owns the remaining 27% interest. Under SFAS
    No. 150,  this  mandatory  redemption  requires  Generation  to classify its
    minority  interest in  Southeast  Chicago as a liability  at fair value.  As
    such,  at July 1, 2003,  Generation  reclassified  $52  million of  minority
    interest to other noncurrent liabilities on the Consolidated Balance Sheet.


                                       32
<PAGE>


     Change in Depreciation 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, net of income taxes). As a result of the change,  operating income
     for the nine months ended  September 30, 2003 increased  approximately  $48
     million ($29 million  after  income  taxes)  compared to the same period in
     2002.


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

     InfraSource Sale

                On   September   24,   2003,   Enterprises   sold  the  electric
     construction   and  services,   underground   and  telecom   businesses  of
     InfraSource, Inc. (InfraSource). Cash proceeds to Enterprises from the sale
     were  approximately  $175  million,  net  of  transaction  costs  and  cash
     transferred to the buyer upon sale,  plus a $30 million  subordinated  note
     receivable  maturing in 2011. At September  30, 2003,  the present value of
     the note receivable was approximately $12 million.  In connection with this
     transaction,  Enterprises  entered  into an  agreement  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.  Pursuant to the sales  agreement,  certain  working
     capital adjustments to the purchase price may be made in 2004.

              In  connection  with the  agreement to sell certain  businesses of
     InfraSource,  Enterprises  recorded an impairment  charge during the second
     quarter of 2003 of  approximately  $48  million  (before  income  taxes and
     minority  interest)  pursuant  to SFAS  No.  142  related  to the  goodwill
     recorded within the InfraSource  Reporting Unit.  Management of Enterprises
     primarily  considered  the  negotiated  sales price and the estimated  book
     value of  InfraSource at the time of the closing of the sale in determining
     the  amount of the  goodwill  impairment  charge.  In  connection  with the
     closing of the sale in the third  quarter of 2003,  Enterprises  recorded a
     gain of $44 million (before income taxes),  primarily due to the book value
     of  InfraSource  at the date of closing  being lower than  estimated in the
     second  quarter of 2003.  The net impact of the goodwill  impairment in the
     second quarter and the gain recorded in the third quarter was a loss before
     income taxes and minority  interest of $4 million for the nine months ended
     September  30,  2003.  The net  impact was  recorded  as an  operating  and
     maintenance  expense  within  the  Consolidated  Statements  of Income  and
     Comprehensive Income for the nine months ended September 30, 2003.




                                       33
<PAGE>

     Exelon Thermal Holdings, Inc.

              Enterprises  classified  the  assets  and  liabilities  of certain
     entities  of Exelon  Thermal  Holdings,  Inc.  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 September
     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  September  30,  2003  consist  of the
     following (in millions):

     -------------------------------------------------------------------------
     Cash                                                                $  12
     Property, plant and equipment, net                                     86
     Other long-term assets                                                  2
     Long-term notes receivable                                              9
     -------------------------------------------------------------------------
     Total assets classified as held for sale                            $ 109
     =========================================================================


     -------------------------------------------------------------------------
     Accounts payable, accrued expenses and other current liabilities    $  11
     Debt                                                                   39
     Asset retirement obligation                                             2
     Other long-term liabilities                                             5
     -------------------------------------------------------------------------
     Total liabilities classified as held for sale                       $  57
     =========================================================================

     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 (net
     of income  taxes) on the $84  million  investment  as an other  income  and
     deduction in 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.




                                       34
<PAGE>

              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
     =========================================================================

              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  and/or to fund  certain  reserve  funds and (2) pay
     certain taxes.

              EBG has a $1.25 billion credit facility (EBG Facility),  which was
    entered  into  primarily to finance the  construction  of Mystic 8 and 9 and
    Fore River. The  approximately  $1.1 billion of debt  outstanding  under the
    credit   facility  at  September  30,  2003  is  reflected  in  Generation's
    Consolidated  Balance Sheets as a current liability due to certain events of
    default  described below. The EBG Facility is non-recourse to 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.

              The  EBG  Facility  required  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.  Project  Completion  was not
     achieved by July 12, 2003,  resulting in an event of default  under the EBG
     Facility.  On July 3, 2003,  the  lenders  under the EBG  Facility  and EBG
     executed a letter agreement as a result of which the lenders were 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 and Fore River
     have all begun  commercial  operation,  although they have not yet achieved
     Project Completion.

              As a result of Generation's  continuing evaluation of the projects
     and discussions  with the lenders,  Generation 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,  Generation  expects  to
     continue to provide  administrative and operational  services to EBG in its
     operation of the projects.  Generation informed the lenders of its decision
     to exit and that it will not  provide  additional  funding to the  projects





                                       35
<PAGE>

     beyond its existing contractual obligations.  Generation cannot predict the
     timing of the transition.

              In  connection  with the decision in late July 2003 to  transition
     out of the  ownership  of EBG  and the  projects,  Generation  recorded  an
     impairment charge of its long-lived assets pursuant to SFAS No. 144 of $945
     million ($573 million net of income taxes) in operating expenses within the
     Consolidated Statements of Income and Comprehensive Income during the third
     quarter  of 2003.  In  determining  the  amount of the  impairment  charge,
     management  compared the carrying value of EBG's  long-lived  assets to the
     fair value of those assets.  The fair value of EBG's long-lived  assets was
     determined  using the  estimated  future  discounted  cash flows from those
     assets.  Generation  used a  probability-weighted  approach for  developing
     estimates  of future  cash flows with the most  likely  scenarios  weighted
     higher.  Forecasted  cash flows  incorporated  assumptions  relative to the
     period of time that  Generation  will  continue to own and operate EBG. The
     time required to fully  transition out of ownership of EBG is uncertain and
     subject to change.  Through the  extinguishment of the outstanding debt and
     upon the  finalization of  Generation's  transition out of ownership of EBG
     and the  projects,  Generation's  net charge  (including  the $573  million
     charge discussed above) is estimated to be $550 million after income taxes.


     4. UNCONSOLIDATED INVESTMENTS (Exelon, PECO and Generation)

     Sithe
              Generation  is a 49.9%  owner of Sithe and has  accounted  for the
     investment as an  unconsolidated  equity  investment  through September 30,
     2003.  In the first  quarter of 2003,  Generation  recorded  an  impairment
     charge of $200 million (before income taxes) in other income and deductions
     within  the  Consolidated  Statements  of Income and  Comprehensive  Income
     associated with a decline in the fair value of the Sithe investment,  which
     was  considered  to  be   other-than-temporary.   Generation's   management
     considered  various  factors in the  decision  to impair  this  investment,
     including  management's  negotiations  to sell 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  was
     required.  In the third quarter of 2003,  Generation recorded an additional
     impairment  charge of $55 million (before income taxes) in other income and
     deductions  within the Consolidated  Statements of Income and Comprehensive
     Income to reflect an additional decline in the fair value of its investment
     in Sithe. This additional decline in fair value was primarily  attributable
     to the changes in terms with a new  acquirer,  which  occurred in the third
     quarter of 2003, as described below.

              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
     $1.0 billion and incurred a net loss of approximately $348 million.  Exelon





                                       36
<PAGE>

     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.

              The  book  value of  Generation's  investment  in  Sithe  was $163
     million at September  30, 2003.  For the nine months  ended  September  30,
     2003, Sithe had revenues of $562 million. Generation recorded $6 million of
     equity  method  income for Sithe for the nine months  ended  September  30,
     2003. See Note 2 - New Accounting  Principles and Accounting  Changes for a
     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
     purchase of the 35.2% interest in Sithe owned by Apollo Energy, LLC and the
     14.9% interest owned by  subsidiaries  of Marubeni  Corporation.  The total
     purchase price under the call is based on the terms of the existing Put and
     Call Agreement (PCA) among the parties and is $621 million. The transfer of
     ownership  requires  various  regulatory  approvals,  including the Federal
     Energy Regulatory  Commission (FERC), the state environmental agency in New
     Jersey,  and  expiration  of the Hart Scott Rodino  waiting  period.  Early
     termination of the Hart Scott Rodino  waiting period was granted  effective
     August 22, 2003.

              Under  the terms of the PCA,  the  purchase  price  must be funded
     within six months of the call notice being  issued.  Additionally,  because
     the Federal Power Act restricts  Generation's ownership of more than 50% of
     a qualifying  facility,  the qualifying  facilities  owned by Sithe must be
     sold or restructured  before closing to preserve their status as qualifying
     facilities.  See below  for  information  regarding  a  separate  agreement
     reached by Sithe to sell six U.S. generating facilities,  each a qualifying
     facility,  and an entity holding Sithe's Canadian  assets.  At the closing,
     Sithe is expected to distribute in excess of $600 million of available cash
     to Generation.

              On  August  13,  2003,  Generation  announced  an  agreement  with
     entities  controlled  by Reservoir  Capital  Group  (Reservoir),  a private
     investment  firm,  to sell a 50%  interest in Sithe in  exchange  for $75.8
     million in cash.  The sale will occur  after  Generation's  purchase of the
     remaining 50.1% interest in Sithe. The sale requires  approval by the FERC,
     a  Hart  Scott  Rodino  filing  and a  filing  with  the  state  regulatory
     commission  in New  York.  Both of these  filings  have  been  made.  Early
     termination of the Hart Scott Rodino  waiting period was granted  September
     30, 2003. The sale is expected to close in the fourth quarter of 2003.

              Both  Generation  and  Reservoir's  50% interests in Sithe will be
     subject to put and call  options  that could  result in either party owning
     100% of Sithe.  While  Generation's  intent is to fully divest Sithe by the
     end of 2004,  the timing of the put and call  options  vary by acquirer and
     can extend  through March 2006.  The pricing of the put and call options is
     dependent on numerous factors such as the acquirer, date of acquisition and
     assets owned by Sithe at the time of exercise.




                                       37
<PAGE>

              In a separate  transaction,  Sithe has entered  into an  agreement
     with  Reservoir to sell entities  holding six U.S.  generating  facilities,
     each a qualifying  facility  under the Public Utility  Regulatory  Policies
     Act, and an entity holding  Sithe's  Canadian  assets in exchange for $46.2
     million ($26.2 million in cash and a $20 million  two-year note).  The sale
     requires  approvals  from Sithe's board of directors and  shareholders  and
     regulatory  filings in New Jersey and Canada.  Both of these  filings  have
     been made.  The sale is also  expected  to close in the  fourth  quarter of
     2003. This sale is not contingent on the sale of Generation's  50% interest
     in Sithe to Reservoir.

     AmerGen
              Generation  is a 50% owner of AmerGen  and has  accounted  for the
     investment as an  unconsolidated  equity  investment  through September 30,
     2003. In addition to Generation's 50% ownership of AmerGen, Generation also
     has significant  purchased power agreements (PPAs) with AmerGen. See Note 9
     - Commitments and Contingencies for further discussion of Generation's PPAs
     with AmerGen. The book value of Generation's investment in AmerGen was $306
     million at September  30, 2003.  For the nine months  ended  September  30,
     2003, AmerGen had revenues of $529 million. Generation recorded $84 million
     of equity method  earnings for AmerGen for the nine months ended  September
     30,  2003.  See  Note 15 -  Subsequent  Events  for  information  regarding
     Generation's  agreement  to  purchase  British  Energy's  50%  interest  in
     AmerGen. See Note 2 - New Accounting  Principles and Accounting Changes for
     discussion of AmerGen concerning FIN No. 46.

              At December 31, 2002, AmerGen had total assets of $1.6 billion and
     total liabilities of $1.3 billion.  Of the total  liabilities,  AmerGen had
     $60 million of long-term  debt, $35 million of notes payable to Generation,
     which were subsequently  repaid in 2003, and $26 million of current portion
     of  long-term  debt.  For the year ended  December  31,  2002,  AmerGen had
     revenues and net income of $644 million and $161 million, respectively.

     Other
              Pursuant to FIN No. 46, PECO  deconsolidated  PECO Trust IV during
     the third  quarter  of 2003.  See Note 2 - New  Accounting  Principles  and
     Accounting Changes.


     5. 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  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




                                       38
<PAGE>

     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 was $29 million  (before income taxes).  In
     accordance  with the  Agreement,  ComEd made payments of $17 million during
     the nine months ended September 30, 2003.

              ComEd filed a request on September  12, 2003 with the FERC seeking
     an  adjustment  in  transmission  rates to reflect  nearly $500  million of
     infrastructure  investments  made during the last five years to accommodate
     sizeable regional growth in electricity demand.

              ComEd's  proposed  increase  would  adjust rates from 95 cents per
     kilowatt-month  to $1.18 per  kilowatt-month,  effective  November 1, 2003.
     Transmission  rates were last set in 1999, based on 1998 costs.  Because of
     the rate  freeze  and the  method for  calculating  competitive  transition
     charges  (CTCs)  in  Illinois,   ComEd  expects  that  the  requested  rate
     adjustment will not significantly increase overall revenue. Several parties
     have  intervened  in this rate  proceeding.  The  ultimate  outcome  of the
     proceeding is unknown.


     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 and  subsequent  auction in September  2003, an aggregate of
     267,000 residential  customers will be transferred to alternative  electric
     generation suppliers during December 2003.  Customers  transferred 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.

              On July 25, 2003,  the PUC approved an  adjustment  to the Nuclear
     Decommissioning  Cost Adjustment  clause.  Effective  January 1, 2004, PECO
     will be permitted to recover an additional  $3.6 million  annually,  or $33
     million compared to $29 million previously.





                                       39
<PAGE>

     6.  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 September 30,     Nine Months Ended September 30,
                                                    --------------------------------     -------------------------------
                                                              2003              2002             2003              2002
     -------------------------------------------------------------------------------------------------------------------
<S>                                                            <C>               <C>              <C>               <C>
     Average Common Shares Outstanding                         326               323              325               322
     Assumed Exercise of Stock Options                          --                 1                3                 2
     -------------------------------------------------------------------------------------------------------------------
     Average Dilutive Common Shares Outstanding                326               324              328               324
     ===================================================================================================================
</TABLE>

              The number of stock  options not  included in the  calculation  of
     diluted common shares outstanding due to their  antidilutive  effect was 15
     million  and 5 million for the three and nine months  ended  September  30,
     2003,  respectively,  and 5 million  for the three  and nine  months  ended
     September 30, 2002.








                                       40
<PAGE>


     7. 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 nine months ended
     September 30, 2003 and 2002 and at September 30, 2003 and December 31, 2002
     is as follows:

     Three Months Ended September 30, 2003 and 2002

<TABLE>
<CAPTION>
                                                                                       Corporate and
                                          Energy                                        Intersegment
                                        Delivery     Generation      Enterprises        Eliminations       Consolidated
     -------------------------------------------------------------------------------------------------------------------
     Total Revenues (1):
     <S>                                <C>            <C>             <C>              <C>                  <C>
     2003                             $    2,886     $    2,537      $        437     $       (1,419)      $      4,441
     2002                                  3,162          2,213               509             (1,514)             4,370
     Intersegment Revenues:
     2003                             $       23     $    1,357      $         38     $       (1,418)      $         --
     2002                                     29          1,463                22             (1,514)                --
     Income (Loss) Before Income Taxes:
     2003                             $      479     $     (708)     $         26     $          (11)      $       (214)
     2002                                    591            265                20                (28)               848
     Income Taxes:
     2003                             $      176     $     (280)     $         10     $          (18)      $       (112)
     2002                                    221            102                 5                (31)               297
     Net Income (Loss):
     2003                             $      303     $     (428)     $         16     $            7       $       (102)
     2002                                    370            163                15                  3                551
     -------------------------------------------------------------------------------------------------------------------
<FN>
     (1)  $65  million  and $67  million in utility  taxes are  included  in the
          revenues and expenses  for the three months ended  September  30, 2003
          and 2002,  respectively,  for ComEd.  $61  million  and $64 million in
          utility  taxes are included in the revenues and expenses for the three
          months ended September 30, 2003 and 2002, respectively, for PECO.
</FN>
</TABLE>







                                       41
<PAGE>

     Nine Months Ended  September  30, 2003 and 2002,  September  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>
     2003                             $    7,850     $    6,301      $      1,459     $       (3,374)      $     12,236
     2002                                  7,973          5,233             1,475             (3,436)            11,245
     Intersegment Revenues:
     2003                             $       58     $    3,246      $         74     $       (3,378)      $         --
     2002                                     59          3,309                72             (3,440)                --
     Income (Loss) Before Income Taxes and the Cumulative Effect of Changes in Accounting
     Principles:
     2003                             $    1,478     $     (548)     $        (99)    $          (54)      $        777
     2002                                  1,455            511               115                (84)             1,997
     Income Taxes:
     2003                             $      558     $     (209)     $        (37)    $          (54)      $        258
     2002                                    547            198                46                (67)               724
     Cumulative Effect of Changes in Accounting Principles:
     2003                             $        5     $      108      $         (1)    $           --       $        112
     2002                                     --             13              (243)                --               (230)
     Net Income (Loss):
     2003                             $      925     $     (231)     $        (63)    $           --       $        631
     2002                                    908            326              (174)               (17)             1,043
     Total Assets:
     September 30, 2003               $   27,309     $   13,240      $        877     $       (2,282)      $     39,144
     December 31, 2002                    26,550         11,007             1,297             (1,369)            37,485
     -------------------------------------------------------------------------------------------------------------------
<FN>
     (1)  $178  million and $181  million in utility  taxes are  included in the
          revenues and expenses for the nine months ended September 30, 2003 and
          2002,  respectively,  for  ComEd.  $159  million  and $157  million in
          utility  taxes are  included in the revenues and expenses for the nine
          months ended September 30, 2003 and 2002, respectively, for PECO.
</FN>
</TABLE>


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

              During the three and nine  months  ended  September  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 September 30, 2003             $      12      $     6        $    241      $   (12)   $     247
     Three months ended September 30, 2002                   (36)          --             (24)           4          (56)
     Nine months ended September 30, 2003                      7           11              50          (10)          58
     Nine months ended September 30, 2002                    (52)          (1)           (130)          19         (164)
     -------------------------------------------------------------------------------------------------------------------
</TABLE>




                                       42
<PAGE>

              During the three and nine  months  ended  September  30,  2003 and
     2002,  Generation  recognized net MTM gains (losses) in purchased  power on
     outstanding  non-trading energy derivative contracts not designated as cash
     flow hedges  included in the  Consolidated  Balance Sheets at September 30,
     2003 and 2002 as follows:

<TABLE>
<CAPTION>
                                                                                                      2003         2002
     -------------------------------------------------------------------------------------------------------------------
     <S>                                                                                           <C>        <C>
     Three months ended September 30,                                                              $   (18)   $       1
     Nine months ended September 30,                                                                   (17)          11
     -------------------------------------------------------------------------------------------------------------------
</TABLE>

              During the three and nine  months  ended  September  30,  2003 and
     2002,  Generation  recognized  net MTM  losses  in  operating  revenues  on
     outstanding  proprietary  trading  contracts  included in the  consolidated
     balance sheets at September 30, 2003 and 2002 as follows:

<TABLE>
<CAPTION>
                                                                                                      2003         2002
     -------------------------------------------------------------------------------------------------------------------
     <S>                                                                                           <C>        <C>
     Three months ended September 30,                                                              $    --    $      --
     Nine months ended September 30,                                                                    (4)         (13)
     -------------------------------------------------------------------------------------------------------------------
</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 September  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     $   (103)      $    12   $    (80)
     -------------------------------------------------------------------------------------------------------------------
</TABLE>

                As of September 30, 2003,  ComEd expects to amortize  during the
     next twelve  months $6 million of  regulatory  assets for settled cash flow
     swaps.  During the three and nine months ended September 30, 2003 and 2002,
     ComEd  reclassified   amounts  between  other   comprehensive   income  and
     regulatory assets for cash flow swaps settled as follows:

<TABLE>
<CAPTION>
                                                                                                 2003             2002
     -------------------------------------------------------------------------------------------------------------------
     <S>                                                                                     <C>                <C>
     Three months ended September 30, (net of tax of $2 and $0, respectively)                 $    (4)          $    --
     Nine months ended September 30, (net of tax of ($19) and ($4), respectively)                  26                 6
     -------------------------------------------------------------------------------------------------------------------
</TABLE>

              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 an anticipated debt issuance.  In connection with
     the 2003 issuances of First Mortgage Bonds,  forward-starting interest rate
     swaps with an aggregate notional amount of $1,070 million were settled with
     net proceeds to counterparties  of $45 million ($19 million,  net of income
     taxes) that has been deferred in regulatory  assets and is being  amortized
     over the life of the First  Mortgage  Bonds as a net  increase  to interest
     expense.  See  Note  12 -  Long-Term  Debt  and  Preferred  Securities  for
     additional  information regarding the issuance of the First Mortgage Bonds.
     At September 30, 2003, ComEd had settled all of its forward-starting swaps.




                                       43
<PAGE>

              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 are  recorded  in  earnings.
     However, as long as the hedge remains effective,  changes in the fair value
     of the  swaps  are  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 September
     30, 2003,  these swaps had an  aggregate  fair market value of $39 million,
     which was classified as other  deferred  debits and other assets within the
     Consolidated Balance Sheets.

              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.  These interest rate
     swaps were  designated  as cash flow hedges as defined by SFAS No. 133, and
     as such,  changes  in fair  value of the swaps  will be  recorded  in other
     comprehensive  income. At September 30, 2003, these interest rate swaps had
     an aggregate fair market value exposure of $11 million based on the present
     value  difference  between the contract  and market rates at September  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 of 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 12 - 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 September  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.  The fair market value
     exposure of these swaps, designated as cash flow hedges, is $91 million.

              Generation  has entered into interest rate swaps with an aggregate
     notional   amount  of  $400  million  to  manage  interest  rate  exposures
     associated  with an anticipated  debt  issuance.  As of September 30, 2003,
     these swaps had an  aggregate  fair market  value  exposure of less than $1
     million  based on the present  value  difference  between the  contract and
     market rates at September 30, 2003.





                                       44
<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
     for the securities held in these trust accounts.

<TABLE>
<CAPTION>
                                                                                                     September 30, 2003
                                                        ---------------------------------------------------------------
                                                                               Gross            Gross
                                                         Amortized        Unrealized       Unrealized         Estimated
                                                              Cost             Gains           Losses        Fair Value
     -------------------------------------------------------------------------------------------------------------------
     <S>                                                  <C>              <C>               <C>              <C>
     Cash and cash equivalents                            $     85         $      --         $     --         $      85
     Equity securities                                       1,918               161             (369)            1,710
     Debt securities
        Government obligations                               1,018                51               (4)            1,065
        Other debt securities                                  538                30              (24)              544
     -------------------------------------------------------------------------------------------------------------------
     Total debt securities                                   1,556                81              (28)            1,609
     -------------------------------------------------------------------------------------------------------------------
     Total available-for-sale securities                  $  3,559         $     242         $   (397)        $   3,404
     ===================================================================================================================
</TABLE>

              Net  unrealized   losses  of  $155  million  were   recognized  in
     regulatory   assets,    regulatory   liabilities   or   accumulated   other
     comprehensive  income in Exelon's  Consolidated  Balance Sheet at September
     30,  2003.  Net  unrealized  losses  of $155  million  were  recognized  in
     noncurrent  affiliate  payables,   noncurrent   affiliate   receivables  or
     accumulated other comprehensive income in Generation's Consolidated Balance
     Sheet as of September 30, 2003. Net unrealized  losses of $346 million were
     recognized in accumulated  depreciation and accumulated other comprehensive
     income in the  Consolidated  Balance  Sheets of  Generation at December 31,
     2002.

              During the three and nine  months  ended  September  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 September 30,       Nine Months Ended September 30,
                                   --------------------------------       -------------------------------
                                                  2003         2002                    2003         2002
---------------------------------------------------------------------------------------------------------
<S>                                          <C>          <C>                     <C>          <C>
     Proceeds from sales                     $     618    $     295               $   1,880    $   1,184
     Gross realized gains                          138           12                     203           43
     Gross realized losses                        (141)         (21)                   (194)         (77)
---------------------------------------------------------------------------------------------------------
</TABLE>

              Net  realized  losses of $3 million  and $11 million for the three
     months ended  September 30, 2003 and 2002,  respectively,  were recorded in
     other  income and  deductions.  Net  realized  gains of $9 million  and net
     realized losses of $32 million for the nine months ended September 30, 2003
     and 2002, respectively,  were recorded in other income and deductions.  Net
     realized losses of $2 million were  recognized in accumulated  depreciation
     at September 30, 2002. The available-for-sale  securities held at September
     30, 2003 have an average  maturity  of six to ten years.  The cost of these
     securities was determined on the basis of specific identification.





                                       45
<PAGE>


     9. 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 in the 2002 Form 10-K.  See Note 2 - New  Accounting  Principles
     and Accounting  Changes of this Form 10-Q for further discussion of nuclear
     decommissioning commitments and contingencies.

     Environmental Liabilities

                As of September  30,  2003,  Exelon had accrued $117 million for
     environmental  investigation  and  remediation  costs that currently can be
     reasonably  estimated,  including  $93 million for  manufactured  gas plant
     (MGP)  investigation and remediation.  Exelon has identified 70 sites where
     former  MGP   activities   have  or  may  have   resulted  in  actual  site
     contamination.

              As of  September  30,  2003,  ComEd had  accrued  $74  million for
     environmental  investigation  and  remediation  costs that currently can be
     reasonably  estimated.  This reserve included $69 million  (discounted) for
     MGP investigation and remediation.

              As  of  September   30,   2003,   PECO  had  accrued  $33  million
     (undiscounted)  for environmental  investigation and remediation costs that
     currently  can be  reasonably  estimated,  including  $24  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 14 - Supplemental Financial Information).

              As of  September  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.





                                       46
<PAGE>

     Energy Commitments

              Generation  had  long-term  commitments  as of September  30, 2003
     relating to the net purchase and sale of energy,  capacity and transmission
     rights from  unaffiliated  utilities,  including  Midwest  Generation,  LLC
     (Midwest  Generation),  AmerGen and others,  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>
     2003                  $      129                $     939           $      98        $     537                 $     19
     2004                         753                    2,064                 515            1,324                      110
     2005                         415                      867                 410              378                       86
     2006                         405                      236                 423              251                        3
     2007                         488                       81                 431              237                       --
     Thereafter                 4,113                        1               1,863              878                       --
     ------------------------------------------------------------------------------------------------------------------------
     Total                 $    6,303                $   4,188           $   3,740        $   3,605                 $    218
     ========================================================================================================================

     <FN>
     (1)  Net Capacity Purchases  includes Midwest Generation  commitments as of
          September 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.  See  Note  15 -  Subsequent  Events  for  additional
          information regarding the PPAs with Midwest Generation,  including the
          MWs  contracted  for in 2004.  Net  Capacity  Purchases  also  include
          capacity  sales to TXU  Corp.  (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 through April 9,
          2009.  Generation  has agreed to purchase all the energy from TMI from
          January 1, 2002 through  December 31, 2014.  Generation  has 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  Clinton's  license issued
          by the U.S. Nuclear  Regulatory  Commission (NRC) expires in 2026. See
          Note  15 -  Subsequent  Events  regarding  Generation's  agreement  to
          purchase British Energy's interest in AmerGen.

     (3)  Transmission  Rights Purchases include  estimated  commitments in 2004
          and 2005 for additional  transmission  rights that will be required to
          fulfill firm sales contracts.
</FN>
</TABLE>

              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. Under the ComEd PPA, prices
     for  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,





                                       47
<PAGE>

     which  could  include  Generation.  The  ComEd PPA for 2005 and 2006 may be
     extended to a full requirements  contract as a result of the Agreement (see
     Note 5 -  Regulatory  Issues).  Under  the  Agreement,  various  interested
     parties have agreed to not oppose such an extension.

              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.  This amount will  increase to $33 million  effective
     January  1,  2004 as a  result  of a July  2003  PUC  order.  See  Note 5 -
     Regulatory  Issues.  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. See Note
     19  -  Commitments  and  Contingencies  in  Exelon's  2002  Form  10-K  for
     additional  information  regarding this  litigation.  On June 13, 2003, the
     court dismissed the amended  complaint with prejudice.  The plaintiffs have
     not appealed 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 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.  In July  2003,  ComEd  and the  municipal
     customers executed a settlement agreement ending the litigation.  Under the
     settlement,  ComEd  paid a total of  approximately  $3 million to the three
     municipalities during the third quarter of 2003.

              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





                                       48
<PAGE>

     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
     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.  While  ComEd  cannot  currently  predict  the  outcome of this
     action,  ComEd does not believe that it will have a material adverse impact
     on ComEd's results of operations.

              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. In an order
     dated October 3, 2003, the court approved the settlement.  A portion of the
     settlement  may be covered by insurance.  ComEd has  remaining  reserves of
     approximately $3 million related to unpaid claims and costs.

     PECO and Generation
              Real Estate Tax Appeals.  PECO and Generation are each challenging
     real estate taxes assessed on nuclear  plants since 1997.  PECO is involved
     in litigation in which it is contesting  Pennsylvania Public Utility Realty
     Tax Act of March 4, 1971, as amended (PURTA) taxes assessed in 1997 and has
     appealed  local real estate  assessments  for 1998 and 1999 on its formerly
     owned Limerick  Generating Station  (Montgomery  County, PA) (Limerick) and
     Peach Bottom Atomic Power Station (York County,  PA) (Peach Bottom) plants.
     Generation  is involved in real estate tax appeals for 2000  through  2003,
     also regarding the valuation of its Limerick and Peach Bottom  plants,  its
     Quad Cities  Station (Rock Island  County,  IL) and,  through its ownership
     interest in AmerGen, TMI (Dauphin County, PA).

              During  the third  quarter  of 2003,  upon  completion  of updated
     nuclear plant appraisal studies, PECO and Generation recorded reductions of
     $58  million  and $15  million,  respectively,  to  reserves  recorded  for
     exposures  associated with the real estate taxes. While PECO and Generation
     believe the resulting reserve balances as of September 30, 2003 reflect the
     most  likely  probable  expected  outcome  of the  litigation  and  appeals
     proceedings in accordance with SFAS No. 5, "Accounting for  Contingencies,"
     the ultimate outcome of such matters could result in additional unfavorable
     or favorable  adjustments to the consolidated  financial statements of PECO
     or Generation, and such adjustments could be material.




                                       49

<PAGE>

     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 totaled $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.  On
     September 5, 2003,  plaintiffs appealed the Tenth Circuit's decision to the
     United  States  Supreme  Court.  Cotter  has  filed  its  response  to  the
     plaintiff's petition.

              On February 18, 2000,  ComEd sold Cotter to an unaffiliated  third
     party.  As part of the 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. Generation
     cannot  predict the ultimate  outcome of the cases.

              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,
     and, as such, no amounts have been accrued as of September 30, 2003.





                                       50
<PAGE>

              Raytheon Litigation.  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 EPC Agreement. Hearings by
     the  Arbitration  Court with respect to damages were  conducted and a final
     decision  is expected in the fourth  quarter of 2003.  Generation  believes
     that Sithe New England properly  rejected  Raytheon's  request for a change
     order and that  Raytheon's  damage claims are inflated.  In addition to its
     asserted  claims,  Raytheon  has  indicated  that it will bring  additional
     claims for  damages.  Generation  will  continue to  vigorously  defend its
     position in the litigation  and contest any  additional  claims that may be
     asserted.

              On  August  29,  2003,   Raytheon  filed  an  action  against  two
     subsidiaries  of EBG  (Project  Companies)  and BNP Paribas in the Superior
     Court of the  Commonwealth  of  Massachusetts.  Raytheon  alleged  that the
     Project Companies and BNP Paribas failed to provide adequate assurance that
     Raytheon  would be paid the remaining  amounts due under the Fore River and
     Mystic   construction   contracts.   Raytheon  sought:  (1)  an  injunction
     preventing the Project  Companies and BNP Paribas from drawing upon certain
     letters of credit  guaranteeing  Raytheon's  performance;  (2) the right to
     terminate the construction contracts; and (3) an order allowing Raytheon to
     seize  project  funds   totaling   approximately   $40  million.   Raytheon
     subsequently dismissed BNP Paribas from the litigation. On October 9, 2003,
     the court issued a  preliminary  injunction  preserving  the status quo and
     preventing  the Project  Companies  from drawing upon the letters of credit
     until such time as the court decides  Raytheon's pending motion for partial
     summary  judgment.  The court has heard  argument on Raytheon's  motion for
     partial summary judgment but has not announced any decision.  Generation is
     unable to predict the ultimate outcome of these legal proceedings.

              Clean Air Act. On June 1, 2001,  the EPA issued to EBG a Notice of





                                       51
<PAGE>

     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 certain generating units in Everett,  Massachusetts (Mystic
     Station).  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 Exelon 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  operating  units at the  plant.  Mystic  Station  also  undertook  an
     extensive  opacity  monitoring  and testing  program for all four operating
     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  operating  units to a lower sulfur fuel oil by September
     1, 2002. The Compliance Order did 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.  Generation  cannot  reasonably  predict the
     ultimate outcome of the settlement discussions.

     Exelon, ComEd, PECO and Generation
              Exelon,  ComEd,  PECO and Generation are involved in various other
     litigation  matters  that are being  defended  and handled in the  ordinary
     course  of  business,  and  Exelon,  ComEd,  PECO and  Generation  maintain
     accruals for such costs that are probable of being  incurred and subject to
     reasonable estimation. 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.











                                       52
<PAGE>

     Commercial Commitments

              Exelon, ComEd, PECO and Generation's  commercial commitments as of
     September 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, were 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>
     Letters of credit (non-debt) (a)      $      121     $     29        $      92          $     --         $      --
     Letters of credit (long-term debt) (b)       413           50              363                --                --
     Preferred securities guarantees (c)          528           --               --                --               528
     Guarantees of long-term debt (d)              41           --                2                --                39
     Midwest Generation Capacity
       Reservation Agreement guarantee (e)         33             1               7                 7                18
     Other
     -----
     Guarantees of letters of credit (f)           28            4               24                --                --
     Performance guarantees (g)                   112           --               --                --               112
     Surety bonds (h)                             622          197              256                12               157
     Energy marketing contract
        guarantees (i)                            208           91              113                 4                --
     Nuclear insurance guarantees (j)           1,559           --               --                --             1,559
     Lease guarantees (k)                          10           --               --                 1                 9
     EBG equity guarantee (l)                      38           38               --                --                --
     Fuel purchase agreements (m)               2,130          139              791               586               614
     ------------------------------------------------------------------------------------------------------------------
     Total                                 $    5,843     $    549        $   1,648          $    610         $   3,036
     ==================================================================================================================

                                                                                                      Expiration within
                                                -----------------------------------------------------------------------
                                                                                                                   2008
     ComEd                                      Total         2003        2004-2005         2006-2007        and beyond
     ------------------------------------------------------------------------------------------------------------------
     Related to Obligations Recorded on the Balance Sheet
     ----------------------------------------------------
     Letters of credit (non-debt) (a)      $       26     $      1        $      25          $     --         $      --
     Letters of credit (long-term debt) (b)        50           50               --                --                --
     Preferred securities guarantees (c)          350           --               --                --               350
     Midwest Generation Capacity
       Reservation Agreement guarantee (e)         33            1                7                 7                18
     Other
     -----
     Surety bonds (h)                              21           --                3                --                18
     ------------------------------------------------------------------------------------------------------------------
     Total                                 $      480     $     52        $      35          $      7         $     386
     ==================================================================================================================






                                       53
<PAGE>

                                                                                                      Expiration within
                                                -----------------------------------------------------------------------
                                                                                                                   2008
     PECO                                       Total         2003        2004-2005         2006-2007        and beyond
     ------------------------------------------------------------------------------------------------------------------
     Related to Obligations Recorded on the Balance Sheet
     ----------------------------------------------------
     Letters of credit (non-debt) (a)      $       29     $     --        $      29          $     --         $      --
     Preferred securities guarantees (c)          178           --               --                --               178
     Other
     -----
     Surety bonds (h)                              46           --               46                --                --
     ------------------------------------------------------------------------------------------------------------------
     Total                                 $      253     $     --        $      75          $     --         $     178
     ==================================================================================================================

                                                                                                      Expiration within
                                                -----------------------------------------------------------------------
                                                                                                                   2008
     Generation                                 Total         2003        2004-2005         2006-2007        and beyond
     ------------------------------------------------------------------------------------------------------------------
     Related to Obligations Recorded on the Balance Sheet
     ----------------------------------------------------
     Letters of credit (non-debt) (a)      $       16     $      9        $       7          $     --         $      --
     Letters of credit (long-term debt) (b)       363           --              363                --                --
     Other
     -----
     Performance guarantees (g)                   101           --               --                --               101
     Energy marketing contract
       guarantees (i)                              36           36               --                --                --
     EBG equity guarantee (l)                      38           38               --                --                --
     Fuel purchase agreements (m)               2,130          139              791               586               614
     Nuclear insurance guarantee (n)              151           --               --                --               151
     ------------------------------------------------------------------------------------------------------------------
     Total                                 $    2,835     $    222        $   1,161          $    586         $     866
     ==================================================================================================================

<FN>
     (a)  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.
     (b)  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.
     (c)  Preferred  securities  guarantees - Guarantees issued to guarantee the
          preferred securities of the unconsolidated and consolidated subsidiary
          trusts of ComEd and PECO.
     (d)  Guarantees  of  long-term  debt  -  Issued  to  guarantee  payment  of
          Enterprises' debt.
     (e)  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 estimated fair value of this guarantee under FIN 45 of
          $4 million is included as a liability on ComEd's  Consolidated Balance
          Sheets.  Additional  information  regarding this liability is included
          within this section under the heading "General" below.
     (f)  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.
     (g)  Performance guarantees - Guarantees issued to ensure performance under
          specific contracts.
     (h)  Surety bonds - Guarantees  issued  related to contract and  commercial
          surety bonds, excluding bid bonds.
     (i)  Energy  marketing  contract  guarantees - Guarantees  issued to ensure
          performance under energy commodity contracts.
     (j)  Nuclear  insurance   guarantees  -  Guarantees  of  nuclear  insurance
          required  under the  Price-Anderson  Act.  $1.0  billion of this total
          exposure is exempt from the $4.5 billion PUHCA  guarantee limit by SEC
          rule.
     (k)  Lease  guarantees - Guarantees  issued to ensure  payments on building
          leases.
     (l)  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.
     (m)  Fuel purchase  agreements - Commitments  to purchase fuel supplies for
          nuclear and fossil generation.
     (n)  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 $1.4 billion  guarantee
          relating to Generation's directly owned plants that is not included in
          this amount.
</FN>
</TABLE>




                                       54
<PAGE>


     Credit Contingencies

              Generation  is  a   counterparty   to  Dynegy  in  various  energy
    transactions.  The credit ratings of Dynegy are considered  below investment
    grade by two credit rating  agencies.  Generation 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
    September  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  provisions 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 $16 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.

              ComEd and  Generation  are  parties to various  transactions  with
    Midwest Generation. Midwest Generation's credit ratings have been downgraded
    by certain credit rating agencies.  Furthermore, the June 30, 2003 Form 10-Q
    filed by Edison  Mission  Energy (EME),  an  intermediate  parent company of
    Edison Mission  Midwest  Holdings (EMMH) and Midwest  Generation,  indicates
    that EMMH is not expected to have  sufficient  cash to repay $911 million of
    debt when it matures on December 11, 2003;  a failure to repay,  extend,  or
    refinance  the EMMH  obligation  would likely  result in a default under the
    senior secured notes and term loan of Mission Energy Holding Company,  EME's
    parent  company;  and these events could make it necessary for EME to file a
    petition for reorganization under Chapter 11 of the United States Bankruptcy
    Code.  Reorganization  under Chapter 11 of the United States Bankruptcy Code
    does  not  assure   non-performance   under  all  contracts;   however,  the
    reorganization  would increase the possibility of the obligations  described
    in the following two paragraphs reverting to ComEd or Generation.

              In  connection  with  ComEd's  sale in  December  1999  of  fossil
    generating  assets  to  Midwest  Generation,  ComEd  entered  into an agency
    agreement   with  EMMH  and  EME  whereby  EMMH  assumed  the  benefits  and
    liabilities of a long-term coal purchase  contract and a railcar lease.  EME
    guaranteed  EMMH's  performance.  EMMH did not become a direct  party to the
    obligations,   and  ComEd  remained  obligated  and  was  not  released.  In
    connection with the Merger and subsequent restructuring,  Generation assumed
    any contingent  obligation on these  contracts  from ComEd.  In the event of
    EMMH and EME's non-performance under the coal purchase contract,  Generation
    would be required to fulfill the purchase  commitments  that 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 minimum purchase obligation for
    the  contract  years  2003 to 2012 are  estimated  to be  approximately  $81
    million (the net present value of the obligation  approximates  $51 million)
    related to this agreement. The railcar lease covers approximately 1,400 coal
    transport   railcars   through   2014.  In  the  event  of  EMMH  and  EME's
    non-performance  under the railcar  lease,  Generation  would be required to
    fulfill the lease  payments that extend  through 2014.  The remaining  lease
    payments for the railcars  approximate $65 million (the net present value of
    the obligation  approximates $38 million).  However, based on current prices
    for railcars in these particular  markets,  Generation  believes it would be
    able to  effectively  sublease the railcars  without  incurring any exposure
    related to this obligation.


                                       55
<PAGE>


              Generation  and ComEd  have  entered  into other  agreements  with
    Midwest  Generation  and have other related  exposures.  In connection  with
    ComEd's  fossil  generating  asset  sale  to  Midwest  Generation,   Midwest
    Generation  and EME  agreed to  indemnify  ComEd for  various  environmental
    exposures  or  penalties.  Generation  assumed  any  contingent  obligations
    relating to  generation-related  environmental issues of ComEd in connection
    with the Merger  and  subsequent  restructuring.  Exelon  cannot  reasonably
    estimate the possible environmental  exposures or penalties that could arise
    if Midwest Generation or EME do not honor their indemnity to ComEd or if the
    indemnity is discharged in bankruptcy.  Midwest  Generation also indemnified
    Generation and ComEd for approximately 50% of any post-acquisition  asbestos
    claims relating to the plants sold to Midwest Generation. Generation assumed
    any contingent  obligations  of ComEd  relating to these asbestos  claims in
    connection with the Merger and subsequent  restructuring.  The bankruptcy of
    or  non-performance  of Midwest  Generation of its obligations to Generation
    and ComEd for  asbestos  claims could result in  contingent  obligations  to
    Generation and ComEd of up to an estimated $5 million. In addition, ComEd is
    exposed to risks associated with accounts  receivable from  transmission and
    station  power  services  provided  by  ComEd  to  Midwest  Generation.  The
    bankruptcy of or non-performance of Midwest Generation of its obligations to
    ComEd for  transmission  and station power services  provided by ComEd could
    result in ComEd recording a write-off of up to an estimated $3 million.

              Generation accounts for certain derivative  financial  instruments
    under the normal purchases and normal sales exemption of SFAS No. 133. As of
    September  30, 2003,  Generation is a party to forward  energy  purchase and
    sale  contracts  with Midwest  Generation,  which are  accounted for in that
    manner and, as such, are not marked-to-market. If Generation determines that
    the possibility of  non-performance by Midwest Generation on these contracts
    becomes  more  than  remote,   these   contracts  will  be  required  to  be
    marked-to-market  through  earnings,  which would be expected to result in a
    charge to Exelon and  Generation's  results of  operations  and such  charge
    could be material.

     Spent Fuel Storage

               In July  2000,  PECO and the U. S.  Department  of  Energy  (DOE)
     entered  into a settlement  agreement  whereby,  in return for  foregoing a
     breach of contract  lawsuit against the DOE, PECO agreed to receive credits
     against its  contributions  to the Nuclear Waste Fund to cover its costs of
     having to construct and maintain an independent spent fuel storage facility
     at Peach Bottom, a facility co-owned by PECO (now Generation). In September
     2002,  the U.S.  Courts of  Appeals  for the 11th  Circuit  ruled  that the
     settlement  agreement's  credit-based funding mechanism violated provisions
     of the  Nuclear  Waste  Policy  Act.  Generation,  as  successor  to  PECO,
     currently  is in  good  faith  discussions  with  the DOE  regarding  a new
     settlement  agreement  with a different  funding  mechanism.  On August 14,
     2003,  Generation received a letter from the DOE demanding repayment of $40
     million of previously  received  credits from the Nuclear  Waste Fund.  The
     letter also demanded $1.5 million of accrued interest  expense.  Although a
     new settlement would offset Generation's  payments,  Generation nonetheless
     has reserved its 50% ownership share of these amounts.  Because  Generation





                                       56
<PAGE>

     expenses the casks and  capitalizes  the permanent  components of its spent
     fuel storage facilities,  these reserves increased  Generation's  operating
     and  maintenance  expense  approximately  $11 million and its capital  base
     approximately $9 million during the third quarter of 2003. The remainder of
     the recorded  obligation to the DOE will be recovered  from the co-owner of
     the facility.  See Note 9 - Nuclear  Decommissioning and Spent Nuclear Fuel
     Storage in Generation's 2002 Form 10-K 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  $22
     million  from  Midwest  Generation  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) and have made  refundable  prepayments  of $11 million and $1
     million, respectively,  during the nine months ended September 30, 2003 for
     potential  fees  associated  with  these  agreements.  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, ultimate
     net cash outflows to ComEd and PECO related to these agreements will either
     be positive or neutral  depending upon the outcome of the refund claim with
     the IRS. 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.


     10. SEVERANCE BENEFITS (Exelon, ComEd, PECO and Generation)

              Exelon,  ComEd,  PECO and Generation  provide severance and health
     and  welfare  benefits to  terminated  employees  pursuant to  pre-existing
     severance plans primarily  based upon each individual  employee's  years of
     service with Exelon and  compensation  level.  The registrants  account for




                                       57
<PAGE>

     their ongoing severance plans in accordance with SFAS No. 112,  "Employer's
     Accounting for Postemployment Benefits, an amendment of FASB Statements No.
     5 and 43" (SFAS No.  112) and  accrue  amounts  associated  with  severance
     benefits that are considered probable and that can be reasonably estimated.

              As part of the  implementation  of  Exelon's  new  business  model
    referred  to as The  Exelon Way  during  the third  quarter of 2003,  Exelon
    identified  1,042 positions for elimination by the end of 2004. The majority
    of the headcount  reductions  are  professional  and  managerial  employees.
    Exelon  recorded a charge for cash severance of $87 million during the third
    quarter of 2003,  which  represented cash severance costs that were probable
    and could be  reasonably  estimated as of September 30, 2003. In addition to
    cash severance,  Exelon incurred  pension and  postretirement  benefit costs
    associated  with The  Exelon  Way  during  the third  quarter of 2003 of $80
    million.  In total,  Exelon  recorded a charge of $167  million in the third
    quarter for severance and related postretirement health and welfare benefits
    and pension and postretirement  curtailment costs associated with The Exelon
    Way. See Note 11 - Retirement  Benefits for a description of the charges for
    the pension and postretirement  benefit plans.  Exelon based its estimate of
    the number of positions to be eliminated on  management's  current plans and
    its ability to determine  the  appropriate  staffing  levels to  effectively
    operate  the  businesses.   Exelon   anticipates   incurring  further  costs
    associated with The Exelon Way upon identifying  additional  positions to be
    eliminated.  These  costs will be  recorded in the period in which the costs
    can be reasonably estimated.

              The  following  table  details,  by segment,  Exelon's  total cash
     severance  expense recorded as an operating and maintenance  expense within
     the  Consolidated  Statements  of Income and  Comprehensive  Income for the
     three and nine months ended September 30, 2003.

<TABLE>
<CAPTION>
                                                                                       Corporate and
                                          Energy                                        Intersegment
     Cash severance charges             Delivery     Generation      Enterprises        Eliminations       Consolidated
     ------------------------------------------------------------------------------------------------------------------
     <S>                             <C>            <C>             <C>                    <C>            <C>
     Expense Recorded in Three Months Ended
      September 30, 2003              $       50     $       20      $         7            $     10       $         87
     Expense Recorded in Nine Months Ended
      September 30, 2003                      53             24                7                  11                 95
     ------------------------------------------------------------------------------------------------------------------
</TABLE>

              The following  table provides  information on total cash severance
     expense  recorded  as an  operating  and  maintenance  expense  within  the
     Consolidated  Statements of Income and Comprehensive  Income of ComEd, PECO
     and Generation:

<TABLE>
<CAPTION>
     Cash severance charges                                                 ComEd               PECO         Generation
     ------------------------------------------------------------------------------------------------------------------
     <S>                                                           <C>                    <C>            <C>
     Expense Recorded in Three Months Ended
      September 30, 2003                                             $        37            $     13       $         20
     Expense Recorded in Nine Months Ended
      September 30, 2003                                                      37                  16                 24
     ------------------------------------------------------------------------------------------------------------------
</TABLE>




                                       58
<PAGE>

              The following  tables  provide a  reconciliation  of the liability
     recorded by Exelon, ComEd, PECO and Generation for severance benefits:

<TABLE>
<CAPTION>
                                             Balance at                                     Other            Balance at
     Cash severance obligations         January 1, 2003     Additions     Payments    Adjustments    September 30, 2003
     ------------------------------------------------------------------------------------------------------------------
<S>                                            <C>          <C>          <C>            <C>                   <C>
     Exelon                                    $     45     $      95    $    (25)      $       3             $     118
     ComEd                                           15            37         (10)             --                    42
     PECO                                            --            16           --             --                    16
     Generation                                      14            24          (4)              3                    37
     ------------------------------------------------------------------------------------------------------------------
</TABLE>


     11.      RETIREMENT BENEFITS (Exelon, ComEd, PECO and Generation)

              During the third  quarter of 2003,  Exelon  announced an amendment
     related to the benefit  provisions of its  postretirement  welfare  benefit
     plans.  The amendment was effective August 1, 2003 and reduced the benefits
     attributable to prior service through  increased  retiree  cost-sharing for
     medical coverage. The changes in the postretirement welfare plan design due
     to the amendment were incorporated into the August 1, 2003 remeasurement of
     the plan obligation  discussed below. The amendment resulted in a reduction
     of  the   accumulated   projected   benefit   obligation   related  to  the
     postretirement  welfare benefit plans of  approximately  $337 million and a
     reduction  of cost of $36  million.  Exelon  recognized  approximately  $14
     million  of this  cost  reduction  in the  third  quarter  of 2003 with the
     remainder to be recognized in the fourth quarter of 2003.

              Due  to The  Exelon  Way  and  the  overall  reduction  in  active
     employees during the third quarter of 2003, certain defined benefit pension
     plans  and   postretirement   welfare   benefit   plans  were   subject  to
     remeasurement  as of August 1, 2003.  The threshold  basis for  curtailment
     remeasurement  was a  reduction  in future  service  greater  than 5%.  The
     curtailment  of certain of the pension plans resulted in a reduction of the
     additional minimum liability and a decrease in the intangible pension asset
     of $10 million.  Overall,  the projected benefit  obligation of the pension
     plan increased by $1 million due to the curtailment.  The projected benefit
     obligation  associated with the  postretirement  benefit plans increased by
     $17 million due to the curtailment.

              The remeasurements of the plan obligations resulted in accelerated
     recognition of a portion of the prior service cost generated by the pension
     and  postretirement   benefit  plans,   resulting  in  the  recognition  of
     curtailment  charges during the third quarter of 2003. The magnitude of the
     curtailment   charge  differed  by  registrant   based  on  the  number  of
     participants  identified for termination and the amount of the unrecognized
     prior  service  costs at the date of  remeasurement.  The  following  table
     provides   information   regarding  the  curtailment  charges  recorded  in
     operating and  maintenance  expense within the  Consolidated  Statements of
     Income and Comprehensive Income during the three months ended September 30,
     2003 due to the  accelerated  recognition of a portion of the prior service
     cost:





                                       59
<PAGE>


<TABLE>
<CAPTION>
     Curtailment charges                                           Pension plans             Other postretirement plans
     ------------------------------------------------------------------------------------------------------------------
<S>                                                                    <C>                                    <C>
     Exelon                                                            $      11                              $      15
     ComEd                                                                     1                                      1
     PECO                                                                      6                                     10
     Generation                                                                3                                      4
     ------------------------------------------------------------------------------------------------------------------
</TABLE>


              During the third quarter of 2003,  Exelon recognized an additional
     charge  associated with special health and welfare benefits offered through
     The Exelon Way. The  following  table  provides  information  regarding the
     charges  recorded  as an  operating  and  maintenance  expense  within  the
     Consolidated Statements of Income and Comprehensive Income during the three
     months ended September 30, 2003:

<TABLE>
<CAPTION>
     Special health and welfare charges                                                      Other postretirement plans
     ------------------------------------------------------------------------------------------------------------------
<S>                                                                                                           <C>
     Exelon                                                                                                   $      54
     ComEd                                                                                                           20
     PECO                                                                                                            12
     Generation                                                                                                      20
     ------------------------------------------------------------------------------------------------------------------
</TABLE>


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

              Effective July 1, 2003,  ComEd and PECO  reclassified the carrying
     values  of their  preferred  securities  issued  prior to June 1, 2003 from
     equity to liabilities in conjunction with the adoption of SFAS No. 150. The
     total amounts  reclassified  from equity to liabilities  were $422 million,
     $344 million and $78 million for Exelon, ComEd and PECO, respectively.  See
     Note 2 - New Accounting  Principles  and Accounting  Changes for additional
     information regarding the adoption of FIN No. 46 and SFAS No. 150.

              On  September  30,  2003,  ComEd  retired $250 million of variable
     interest medium term notes due September 30, 2003.

              On September 30, 2003, ComEd redeemed $42 million of variable rate
     Pollution  Control  Revenue  Bonds,  1994 B Series,  due  October  15, 2014
     originally issued through the Illinois Development Finance Authority.

              On  September  24,  2003,  ComEd  issued $42  million of  variable
     interest  Pollution  Control  Revenue  Refunding Bonds due November 1, 2019
     through the Illinois Development Finance Authority.

              On August 25,  2003,  ComEd  issued  $250  million of 4.74%  First
     Mortgage Bonds,  due in 2010. These bond issuances were used to finance the
     repayment and early retirement of long-term debt.




                                       60
<PAGE>

              On July 15, 2003, ComEd retired $100 million of its First Mortgage
     Bonds due July 15, 2003.  The 6.625% bonds were  refinanced  with long-term
     debt issued on August 25, 2003.

              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  Financing  I, a wholly owned  financing
     subsidiary of ComEd, redeemed $200 million of trust preferred securities at
     a  redemption  price  of  100%  of  the  principal  amount,   plus  accrued
     distributions.  ComEd  redeemed  $206  million of  subordinated  debentures
     issued to ComEd  Financing I. 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 by ComEd Financing
     III, a wholly owned  financing  subsidiary  of ComEd,  which have an annual
     distribution  rate of 6.35% and are  mandatorily  redeemable  in 2033.  The
     subordinated  debentures,  which  carried an interest  rate of 8.48%,  were
     refinanced with the proceeds from a March 17, 2003 issue of $206 million of
     subordinated  debentures  from ComEd to ComEd  Financing III, 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.

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

              During the nine months ended  September 30, 2003,  Exelon  retired
     $493 million of transitional funding trust notes, comprised of $254 million
     for ComEd and $239 million for PECO.




                                       61
<PAGE>

              During the nine months ended  September 30, 2003,  ComEd  recorded
     prepayment premiums of $15 million and net unamortized premiums,  discounts
     and debt  issuance  expenses  of $57  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.

              During  June  2003,  PECO  issued  $103  million  of  subordinated
     debentures to PECO Trust IV in  connection  with the issuance by PECO Trust
     IV of $100 million of preferred securities with an annual distribution rate
     of 5.75%  that are  mandatorily  redeemable  in 2033.  The trust  preferred
     securities  were  recorded  as  liabilities  of PECO as of June 30, 2003 in
     accordance  with SFAS No. 150.  Effective  July 1, 2003,  PECO Trust IV was
     deconsolidated  from the financial  statements of PECO in conjunction  with
     the  adoption  of FIN No. 46. See Note 2 - New  Accounting  Principles  and
     Accounting   Changes  for  further   information.   The  $103   million  of
     subordinated  debentures  issued by PECO to PECO Trust IV was  recorded  as
     long-term debt to affiliate  within the  Consolidated  Balance Sheets.  The
     proceeds  of the issue were used to redeem the trust  preferred  securities
     and preferred stock discussed below.

              Also on June 24,  2003,  PECO  Energy  Capital  Trust II, a wholly
     owned financing subsidiary of 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. PECO redeemed $52 million of subordinated
     debentures to PECO Energy Capital Trust II.

              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 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 (Pennsylvania).
     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.

              During  the third  quarter of 2003,  an event of default  occurred
     related to the EBG Facility.  See Note 3 - Acquisitions,  Dispositions  and
     Retirements for further information.

              On  September  29,  2003,  Generation  closed  on an $850  million
     revolving  credit  facility that replaced a $550 million  revolving  credit
     facility that had originally  closed on June 13, 2003.  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.  This  note  was
     restructured  in June 2003 to provide for a payment of $210  million of the
     principal on June 16, 2003, payment of $236 million of the principal on the
     earlier of December 1, 2003 or change of control of Generation, and payment





                                       62
<PAGE>

     of the remaining  principal on the earlier of December 1, 2004 or change of
     control of Generation.  At September 30, 2003,  Generation had $640 million
     available under this credit facility.

              Exelon, ComEd, PECO and Generation maintain a $1.5 billion 364-day
     credit facility to support  commercial  paper  issuances.  At September 30,
     2003,  sublimits under the credit facility were $1.0 billion,  $100 million
     and $400  million  for  Exelon  Corporate,  ComEd and  PECO,  respectively.
     Generation  did not have a sublimit  under the  facility at  September  30,
     2003. Exelon Corporate, ComEd and PECO had approximately $720 million, $360
     million and $75 million available under the credit facility,  respectively,
     reflecting  commercial  paper,  letters of credit and loans  outstanding at
     September 30, 2003. At September 30, 2003, commercial paper outstanding was
     $70  million and $12 million at Exelon  Corporate  and PECO,  respectively.
     ComEd and  Generation  did not have any  commercial  paper  outstanding  at
     September 30, 2003.

              See Note 8 - Fair Value of Financial  Assets and  Liabilities  for
     additional  information  regarding  interest rate swaps of ComEd,  PECO and
     Generation.











                                       63
<PAGE>

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

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

<TABLE>
<CAPTION>
                                                                                 Three Months               Nine Months
                                                                          -------------------       -------------------
                                                                          Ended September 30,       Ended September 30,
                                                                          -------------------       -------------------
                                                                            2003         2002         2003         2002
     -----------------------------------------------------------------------------------------------------------------------
     <S>                                                                <C>          <C>         <C>          <C>
     Operating revenues from affiliates
       Generation (1)                                                   $     16     $     22    $      42    $      41
       Enterprises (1)                                                         4            4            7            8
     Purchased power from affiliate
       Generation (2)                                                        885          967        1,984        2,046
     Operating & maintenance from affiliates
       BSC (3)                                                                32           29           84           94
       Enterprises (4, 5)                                                      8            4           14           10
     Interest income from affiliates
       UII (6)                                                                 5            8           17           23
       Exelon intercompany money pool (10)                                     1           --            2           --
       Other                                                                  --           --            1           --
     Capitalized costs
       BSC (3)                                                                 1            3            3            6
       Enterprises (5)                                                        10            3           21           16
     Cash dividends paid to parent                                            94          118          305          353
     -----------------------------------------------------------------------------------------------------------------------

                                                                               September 30, 2003     December 31, 2002
     -----------------------------------------------------------------------------------------------------------------------
     Receivables from affiliates (current)
       UII (6)                                                                          $      --               $    15
       Exelon intercompany money pool (10)                                                    147                    --
       Other                                                                                    4                    --
     Receivables from affiliates (noncurrent)
       UII (6)                                                                              1,071                 1,284
       Generation (8)                                                                       1,144                    --
       Other                                                                                   13                    16
     Payables to affiliates (current)
       Generation decommissioning (7)                                                          11                    59
       Generation (1, 2)                                                                      162                   339
       BSC (3)                                                                                 13                    18
     Payables to affiliates (noncurrent)
       Generation decommissioning obligation (7)                                               33                   218
       Other                                                                                    6                     6
     Shareholders' equity - receivable from parent (9)                                        509                   615
     -----------------------------------------------------------------------------------------------------------------------

<FN>
     (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 9 - 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 (an Enterprises  company) 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.





                                       64
<PAGE>

     (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.

     (7)  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.

     (8)  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.

     (9)  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.

     (10) ComEd  participates in Exelon's  intercompany  money pool. ComEd earns
          interest  on its  investments  in the money  pool at a market  rate of
          interest.
</FN>
</TABLE>

     Exelon and PECO
     Exelon and PECO's financial statements reflect  related-party  transactions
     with its unconsolidated  financing subsidiary,  PECO Trust IV, as reflected
     in the tables below.
<TABLE>
<CAPTION>
                                                                                 Three Months               Nine Months
                                                                                 ------------               -----------
                                                                          Ended September 30,       Ended September 30,
                                                                          -------------------       -------------------
                                                                            2003         2002         2003         2002
     ------------------------------------------------------------------------------------------------------------------
     <S>                                                               <C>          <C>          <C>          <C>
     Interest expense to PECO Trust IV (1)                             $       2    $      --    $       2    $      --
     ------------------------------------------------------------------------------------------------------------------


                                                                               September 30, 2003     December 31, 2002
     ------------------------------------------------------------------------------------------------------------------
     Note receivable from PECO Trust IV (long-term) (1)                             $           1             $      --
     Debt to PECO Trust IV (1)                                                                103                    --
     ------------------------------------------------------------------------------------------------------------------
<FN>
     (1)  As of July 1, 2003, PECO Trust IV, a wholly owned financing subsidiary
          of PECO  created  in May 2003,  is no longer  consolidated  within the
          financial  statements of Exelon or PECO pursuant to the  provisions of
          FIN No. 46.  Amounts  owed to PECO Trust IV are  recorded as long-term
          debt to affiliate within the Consolidated Balance Sheets, and interest
          owed to PECO  Trust IV is  recorded  as  interest  expense  within the
          Consolidated  Statements of Income and  Comprehensive  Income.  A note
          receivable was recorded as of July 1, 2003  representing  amounts owed
          to PECO from PECO  Trust IV  related  to debt  issuance  costs paid by
          PECO.  PECO holds $3 million of the common  securities  issued by PECO
          Trust IV.
</FN>
</TABLE>






                                       65
<PAGE>

     PECO
              In addition to the transactions  described above, PECO's financial
     statements  reflect a number of related-party  transactions as reflected in
     the table below.

<TABLE>
<CAPTION>
                                                                                 Three Months               Nine Months
                                                                                 ------------               -----------
                                                                          Ended September 30,       Ended September 30,
                                                                          -------------------       -------------------
                                                                            2003         2002         2003         2002
     ------------------------------------------------------------------------------------------------------------------
     <S>                                                               <C>          <C>          <C>          <C>
     Operating revenues from affiliate
       Generation (1)                                                  $       3    $       3    $       8    $       9
       Other                                                                  --           --            1           --
     Purchased power from affiliate
       Generation (2)                                                        421          441        1,101        1,090
     Operating & maintenance from affiliates
       BSC (3)                                                                14           10           36           36
       Enterprises (4)                                                        --            5            3           21
     Capitalized costs
       BSC (3)                                                                 1            2            6            8
       Enterprises (4)                                                        10            6           23           16
     Cash dividends paid to parent                                            79           85          244          255
     ------------------------------------------------------------------------------------------------------------------

                                                                                September 30, 2003    December 31, 2002
     ------------------------------------------------------------------------------------------------------------------
     Payables to affiliates (current)
       Generation (2)                                                                   $      123            $     124
       BSC (3)                                                                                  18                   26
       Enterprises (4)                                                                          --                   19
       Other                                                                                     1                    1
     Payable to affiliate (noncurrent)
       Generation (5)                                                                            7                   --
     Shareholders' equity - receivable from parent (6)                                       1,661                1,758
     ------------------------------------------------------------------------------------------------------------------
<FN>
     (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 9 - Commitments  and  Contingencies  for further  information
          regarding the PPA.
     (3)  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  implementation  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.
</FN>
</TABLE>








                                       66
<PAGE>


     Exelon and Generation
     Exelon  and  Generation's   financial   statements  reflect   related-party
     transactions  with  unconsolidated  affiliates  as  reflected in the tables
     below.
<TABLE>
<CAPTION>
                                                                                 Three Months               Nine Months
                                                                                 ------------               -----------
                                                                          Ended September 30,       Ended September 30,
                                                                          -------------------       -------------------
                                                                            2003         2002         2003         2002
     ------------------------------------------------------------------------------------------------------------------
     <S>                                                               <C>          <C>          <C>          <C>
     Purchased power from AmerGen (1)                                  $     133    $     104    $     310    $     220
     Interest income from AmerGen (2)                                         --            1            1            2
     Interest expense to Sithe (3)                                             2           --            7           --
     Services provided to AmerGen (4)                                         50           16           85           46
     Services provided to Sithe (5)                                           --           --            1            1
     Services provided by Sithe (6,7)                                         --            3            5            5
     ------------------------------------------------------------------------------------------------------------------

                                                                               September 30, 2003     December 31, 2002
     ------------------------------------------------------------------------------------------------------------------
     Net receivable from AmerGen (1,2,4)                                            $          --             $      39
     Net payable to AmerGen (1,2,4)                                                            22                    --
     Net receivable from Sithe (3,5,6,7)                                                        1                    --
     Net payable to Sithe (3,5,6,7)                                                            --                     7
     Note payable to Sithe (3)                                                                326                   534
     ------------------------------------------------------------------------------------------------------------------

<FN>
     (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. See Note 15 -
          Subsequent Events regarding Generation's agreement to purchase British
          Energy's interest in AmerGen.
     (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.  The principal  balance of the loan was paid
          in full during the second quarter of 2003.
     (3)  Under the terms of the  agreement to acquire  Exelon New England dated
          November 1, 2002,  Generation  issued a $534  million note due 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,  $236 million
          of the  principal  is to be paid by December 1, 2003 or upon change of
          control of  Generation,  and the  balance of the note is to be paid by
          December  1, 2004 or upon  change of control of  Generation.  The note
          bears  interest  at the  rate  equal to LIBOR  plus  0.875%.  Interest
          accrued on the note as of September 30, 2003 was less than $1 million.
     (4)  Under a service  agreement  dated March 1, 1999,  Generation  provides
          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
          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 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
          2002.
</FN>
</TABLE>




                                       67
<PAGE>


     Generation
              In  addition to the  transactions  described  above,  Generation's
     financial  statements  reflect a number of  related-party  transactions  as
     reflected in the tables below.

<TABLE>
<CAPTION>
                                                 Three Months Ended September 30,       Nine Months Ended September 30,
                                                 --------------------------------       -------------------------------
                                                             2003            2002                2003              2002
     ------------------------------------------------------------------------------------------------------------------
     <S>                                                  <C>            <C>                 <C>              <C>
     Operating revenues from affiliates
       ComEd (1)                                          $   885        $    949            $  1,984         $   2,029
       PECO (1)                                               421             441               1,101             1,090
       Exelon Energy Company (2)                               51              73                 161               190
     Purchased power from affiliates
       ComEd (4)                                               11              --                  31                13
       PECO (4)                                                --              --                  --                 1
       Exelon Energy Company (4)                               --               6                   9                13
     Operating & maintenance from affiliates
       ComEd (4)                                                5               4                  11                11
       PECO (4)                                                 3               3                   8                 8
       BSC (6)                                                 46              33                 117               117
     Interest expense - affiliate
       Exelon intercompany money pool (8)                       1              --                   2                --
       Exelon (3)                                              --               1                   2                 3
     Cash distribution paid to member                          71              30                 116                30
     ------------------------------------------------------------------------------------------------------------------

                                                                               September 30, 2003     December 31, 2002
     ------------------------------------------------------------------------------------------------------------------
     Receivables from affiliates (current)
       ComEd  (1)                                                                     $       162             $     339
       ComEd decommissioning receivable (7)                                                    11                    59
       PECO (1)                                                                               123                   124
       BSC (6)                                                                                 --                    14
       Exelon Energy Company (2)                                                               16                    19
       Other                                                                                    1                    --
     Receivables from affiliates (noncurrent)
       ComEd decommissioning receivable (7)                                                    33                   218
       PECO decommissioning receivable (5)                                                      7                    --
       Other                                                                                   --                     2
     Payables to affiliates (current)
       Exelon (3)                                                                               2                     3
       BSC (6)                                                                                 43                    --
     Payable to affiliate (noncurrent)
       ComEd decommissioning (5)                                                            1,144                    --
     Notes payable to affiliate - Exelon (3)                                                    4                   329
     Notes payable to affiliates - Exelon intercompany money pool (8)                         147                    --
     ------------------------------------------------------------------------------------------------------------------

<FN>
     (1)  Effective January 1, 2001, Generation entered into PPAs with ComEd and
          PECO.  See  Note  9  -  Commitments  and   Contingencies  for  further
          information  on the PPAs. In 2002,  Generation  recorded  transmission
          expense to ComEd of $18  million and $17 million in the three and nine
          months, respectively, as a reduction of revenue.
     (2)  Generation  sells  power to  Exelon  Energy  Company  (an  Enterprises
          company).
     (3)  Generation  has a payable to Exelon  related  to certain  compensation
          plans.






                                       68
<PAGE>

     (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.  In 2002,
          Generation recorded  transmission  expense to ComEd of $18 million and
          $17 million in the three and nine months, respectively, as a reduction
          of revenue.
     (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.
     (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   participates   in  Exelon's   intercompany   money  pool.
          Generation  pays interest on its  borrowings  from the money pool at a
          market rate of interest.
</FN>
</TABLE>


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

<TABLE>
<CAPTION>
                                                                                        September 30,      December 31,
     ComEd                                                                                       2003              2002
     ------------------------------------------------------------------------------------------------------------------
     <S>                                                                                   <C>               <C>
     Regulatory Assets (Liabilities)
     Nuclear decommissioning
       (see Note 2 - New Accounting Principles and Accounting Changes)                      $  (1,144)        $      --
     Nuclear decommissioning costs for retired plants                                              --               248
     Recoverable transition costs                                                                 141               175
     Reacquired debt costs and interest rate swap settlements                                     163                84
     Recoverable deferred income taxes                                                            (64)              (68)
     Other                                                                                         24                 8
     ------------------------------------------------------------------------------------------------------------------
     Total                                                                                  $    (880)        $     447
     ==================================================================================================================


                                                                                        September 30,      December 31,
     PECO                                                                                        2003              2002
     ------------------------------------------------------------------------------------------------------------------
     Regulatory Assets
     Competitive transition charge                                                          $   4,381         $   4,639
     Recoverable deferred income taxes                                                            752               729
     Non-pension postretirement benefits                                                           60                64
     Reacquired debt costs                                                                         49                53
     Nuclear decommissioning and decontamination funds                                             27                32
     Nuclear decommissioning
       (see Note 2 - New Accounting Principles and Accounting Changes)                              7                --
     MGP regulatory asset (see Note 9 - Commitments and Contingencies)                             16                20
     Compensated absences                                                                           9                 6
     Postemployment benefits                                                                        3                 3
     ------------------------------------------------------------------------------------------------------------------
     Long-term regulatory assets                                                                5,304             5,546
     Deferred energy costs (current asset)                                                         64                31
     ------------------------------------------------------------------------------------------------------------------
     Total                                                                                  $   5,368         $   5,577
     ==================================================================================================================
</TABLE>




                                       69
<PAGE>

              Exelon's  long-term   regulatory  assets  and  liabilities  as  of
     September  30, 2003 were $5,304  million  and $880  million,  respectively.
     Exelon's  long-term  regulatory  assets as of December 31, 2002 were $5,993
     million.

              ComEd's  depreciation,  which is  included  in cost of service for
     rate purposes, includes an estimated cost of dismantling and removing plant
     from service upon  retirement.  ComEd has  estimated  future  removal costs
     embedded in accumulated depreciation related to rate-regulated plant assets
     were  approximately  $1.2 billion at September 30, 2003 in accordance  with
     regulatory accounting practice.

              PECO has historically  incurred removal costs in excess of amounts
     recovered  in rates.  As such,  PECO does not have any amounts  embedded in
     accumulated depreciation as of September 30, 2003.


     15.      SUBSEQUENT EVENTS (Exelon, ComEd and Generation)

     ComEd
              On October 7, 2003,  ComEd redeemed $150 million of First Mortgage
     Bonds,  at a redemption  price of 103.765% of the  principal  amount,  plus
     accrued interest. The bonds, which carried an interest rate of 7.750%, were
     refinanced with long-term debt issued on August 25, 2003.

     Generation
              On October 1, 2003,  Generation notified Midwest Generation of its
     exercise  of  certain   termination  options  under  the  existing  Collins
     Generation  Station and Peaking Unit Purchase Power  Agreements,  releasing
     303 MWs for  2004,  the  fifth and  final  year of the  contract.  With the
     exercise of the  termination  options on the peaking  plants in addition to
     the  exercise  of the options on the coal plants in June 2003 (see Note 9 -
     Commitments and  Contingencies for further  information  regarding the Coal
     Generation  PPA),  the contract  with Midwest  Generation  is finalized for
     2004.  Generation will take 1,696 MWs of non-option coal capacity,  687 MWs
     of option coal capacity,  1,084 MWs of Collins Station capacity and 392 MWs
     of peaking capacity from Midwest  Generation in 2004. In total,  Generation
     has retained  3,859 MWs of capacity  under the terms of the three  existing
     PPAs with Midwest Generation.

                On October 2, 2003,  Mitsubishi Heavy Industries,  LTD (MHI) and
     Mitsubishi  Heavy Industries of America (MHIA) filed a New York state court
     action  against  Exelon  Mystic  Development,  LLC (Mystic) and Exelon Fore
     River  Development,  LLC (Fore  River)  seeking  to enjoin  these  indirect
     subsidiaries  of  Generation  from drawing upon letters of credit posted to
     guarantee MHI's  performance under certain gas turbine  contracts.  MHI and
     MHIA also seek $34  million  from these  entities in  connection  with work
     performed  on these  contracts.  Generation  believes  that Mystic and Fore
     River's contracts with MHI and MHIA have been assigned to Raytheon and that
     the claims against the Generation entities are without merit.

              On October 10,  2003,  Exelon  executed an  agreement  to purchase
     British   Energy's  50%  interest  in  AmerGen  for  $276.5  million.   The
     transaction  is expected to close in the first half of 2004.  The  purchase





                                       70
<PAGE>

     price  matched the offer by FPL Energy,  which  announced on September  11,
     2003 that it intended to buy British  Energy's share of AmerGen.  Under the
     AmerGen limited liability  company  operating  agreement between Exelon and
     British  Energy,  either  party can  exercise  a right of first  refusal by
     matching any bona fide third-party offer agreed to by the other member. See
     Note 4 - Unconsolidated  Investments for additional  information  regarding
     AmerGen.





































                                       71
<PAGE>

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

     (Dollars in millions, unless otherwise noted)

     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  7 of  the  Condensed  Combined  Notes  to  Consolidated
     Financial Statements for further segment information.

     CRITICAL ACCOUNTING ESTIMATES
              Management  of  each  of  the   registrants   makes  a  number  of
     significant  estimates,  assumptions  and judgments in the  preparation  of
     their financial  statements.  See "Management's  Discussion and Analysis of
     Financial  Condition  and  Results  of  Operations  -  Critical  Accounting
     Estimates"  in the 2002 Form 10-K for a  discussion  of the  estimates  and
     judgments   necessary  in  the   registrants'   accounting  for  derivative
     instruments,  regulatory assets and liabilities,  nuclear  decommissioning,
     asset impairments, defined benefit pension and other postretirement welfare
     benefits,  stock-based compensation plans, business combinations,  unbilled
     energy revenues, long-term contract accounting and environmental costs. Set
     forth below is an update to the 2002 Form 10-K.

     Asset Impairments (Exelon, ComEd, PECO and Generation)
              Exelon   evaluates  the  carrying  value  of  long-lived   assets,
     excluding goodwill, when circumstances indicate the carrying value of those
     assets may not be recoverable. The review of assets for impairment requires
     significant  assumptions about operating strategies and estimates of future
     cash  flows.  A  variation  in an  assumption  could  result in a different
     conclusion  regarding the  realizability of the asset. The potential impact
     of recognizing an impairment on the

                                       72
<PAGE>

     assets reported within the Consolidated  Balance Sheets,  as well as on net
     income,  could  be and has  been  material  to the  consolidated  financial
     statements.

              During the second quarter of 2003,  Exelon  recorded an impairment
     charge related to investments  held by  Enterprises  of  approximately  $35
     million   (before   income   taxes).    Management   determined   that   an
     other-than-temporary  decline  in the fair value of these  investments  had
     occurred  and  considered  various  factors  in the  decision  to record an
     impairment of the investments,  including recent third-party  valuations of
     the investments.  The  other-than-temporary  determination  was significant
     because  any  increase  in fair  value  of  these  investments  will not be
     recoverable until they are sold. Had management  determined  otherwise,  no
     impairment  charge  would  have  been  recorded.  The  valuations  of these
     investments,  which  form the basis  for the  impairment  charge,  required
     assumptions  regarding the future earnings  potential of these investments.
     Actual results from these  investments  have fluctuated in the past and are
     expected to continue.

              During the first and third quarters of 2003,  Generation  recorded
     impairment  charges totaling $255 million (before income taxes)  associated
     with a decline in the fair value of its  investment  in Sithe.  In reaching
     that   decision,   management   considered   various   factors,   including
     negotiations   to  sell  its  investment  in  Sithe,   which  indicated  an
     other-than-temporary  decline in fair value. The charges included estimates
     of  potential   guarantees   under  FASB   Interpretation   (FIN)  No.  45,
     "Guarantor's   Accounting  and  Disclosure   Requirements  for  Guarantees,
     Including  Indirect  Guarantees  of  Indebtedness  to Others"  (FIN No. 45)
     associated with the sale of the investment, which are subject to change.

              During  the  third  quarter  of  2003,   Generation   recorded  an
     impairment  charge  related  to the  long-lived  assets  of  Exelon  Boston
     Generating,  LLC (EBG),  an  indirect  subsidiary  of  Generation,  of $945
     million  (before income taxes) due to its decision to transition out of the
     ownership  of  EBG.  See  Note  3  of  the  Condensed   Combined  Notes  to
     Consolidated  Financial Statements for further information.  In determining
     the amount of the impairment charge, management compared the carrying value
     of EBG's  long-lived  assets to their estimated fair value.  The fair value
     was determined using the estimated future  discounted cash flows from those
     assets.  Forecasted  cash flows  incorporated  assumptions  relative to the
     period of time that  Generation  will  continue to own and operate EBG. The
     time required to fully  transition out of ownership of EBG is uncertain and
     subject  to  change.  Exelon  used  a  probability-weighted   approach  for
     developing  estimates  of future cash flows with the most likely  scenarios
     weighted  higher.  A change in  Exelon's  probability  assessment  for each
     scenario  could have a  significant  impact on the  estimated  future  cash
     flows.  Exelon  utilized a  discount  rate  based  upon  valuations  of the
     business developed at the purchase date.

     Goodwill (Exelon, ComEd)
              ComEd had  approximately  $4.7  billion of  goodwill  recorded  at
     September 30, 2003. The goodwill will remain at its recorded  amount unless
     it is  determined  to be  impaired,  which is  based  upon an  analysis  of
     expected  future cash flows.  Exelon and ComEd  perform an  assessment  for
     impairment of their  goodwill at least  annually,  or more  frequently,  if
     events or  circumstances  indicate  that  goodwill  might be impaired.  The
     annual  goodwill  impairment  assessment  will be  performed  in the fourth
     quarter of 2003.  Discounted cash flow models will

                                       73
<PAGE>

     be used to determine  the fair value of the  Reporting  Units in the annual
     assessment. The discounted cash flow models include significant assumptions
     regarding revenue growth rates,  general expense escalation rates,  impacts
     of The Exelon Way,  allowed return on equity and a  risk-adjusted  discount
     rate. These assumptions are subject to change from period to period.

              If an  impairment  is  determined  at  ComEd,  the  amount  of the
    impaired  goodwill will be written-off and expensed at ComEd.  Under current
    regulations,  a significant goodwill impairment may restrict ComEd's ability
    to pay dividends.  ComEd is pursuing  various  solutions to address  ComEd's
    ability to pay dividends if a significant  goodwill impairment exists. Based
    upon  Illinois   legislation,   goodwill   impairments   are  excluded  from
    determining whether or not the earnings cap amount has been met or exceeded.
    A goodwill  impairment  charge at ComEd may not affect  Exelon's  results of
    operations.  Exelon's  goodwill  impairment test would include assessing the
    cash  flows  of the  entire  Energy  Delivery  business  segment  (a  single
    Reporting  Unit,  which includes  PECO, as defined under current  accounting
    guidance), not just ComEd's cash flows.

              In  connection  with an agreement to sell  certain  businesses  of
     InfraSource,  Inc.  (InfraSource),  Exelon  recorded an  impairment  charge
     during the second  quarter of 2003 of  approximately  $48  million  (before
     minority interest and income taxes) related to the goodwill recorded within
     the  InfraSource   Reporting  Unit.  Management  of  Enterprises  primarily
     considered  the negotiated  sales price of  InfraSource in determining  the
     amount of the goodwill  impairment charge. This charge was partially offset
     by a gain recorded during the third quarter of 2003 upon the closing of the
     sale.

     Severance Accounting (Exelon, ComEd, PECO and Generation)
              As  part of the  implementation  of The  Exelon  Way,  Exelon  has
    identified   1,042  positions  for  elimination  by  the  end  of  2004  and
    anticipates  identifying  additional  positions for  elimination in 2005 and
    2006.  Exelon  will  provide  severance  benefits  to  terminated  employees
    pursuant  to   pre-existing   severance  plans  primarily  based  upon  each
    individual  employee's years of service with Exelon and compensation  level.
    The registrants  have recorded  charges in the third quarter of 2003 related
    to severance  benefits  that are  considered  probable and can be reasonably
    estimated in accordance  with Financial  Accounting  Standards  Board (FASB)
    Statement  of Financial  Accounting  Standards  (SFAS) No. 112,  "Employer's
    Accounting for Postemployment  Benefits, an amendment of FASB Statements No.
    5 and 43" (SFAS No.  112).  A  significant  assumption  in  calculating  the
    severance  charge was the  determination  of the number of  positions  to be
    eliminated.  The registrants  based their estimates on management's  current
    plans and its  ability  to  determine  the  appropriate  staffing  levels to
    effectively  operate the businesses.  Exelon  anticipates  incurring further
    costs associated with The Exelon Way upon identifying  additional  positions
    to be  eliminated.  These  costs will be recorded in the period in which the
    costs can be reasonably estimated.

     Defined Benefit Pension and Other Postretirement  Welfare Benefits (Exelon,
     ComEd, PECO and Generation)
              During the third quarter of 2003,  Exelon announced a benefit plan
     amendment that reduced the benefits  attributable  to prior service through
     increased  retiree  cost-sharing  for  medical  coverage.  Furthermore,  in
     connection  with the  implementation  of The  Exelon  Way

                                       74
<PAGE>

     during the third quarter of 2003, the overall reduction in active employees
     triggered a curtailment  charge related to certain  defined benefit pension
     and postretirement  welfare benefit plans.  Curtailment  accounting applies
     when an event  occurs  that  significantly  reduces the  expected  years of
     future service of active plan participants.  The expected reduction in plan
     participants  ranged  between  five and ten  percent of the total  eligible
     participants  of each plan that qualified for curtailment  accounting.  The
     plan  amendment and  curtailments  resulted in  remeasurements  of the plan
     obligations  as of  August 1,  2003.  The total  increase  in net  periodic
     benefit costs due to the curtailments  recorded during the third quarter of
     2003 was $26 million.  Pension and postretirement  costs are anticipated to
     total $234  million in 2003,  including  the effects of the  amendment  and
     curtailments, compared to $111 million in 2002.

              The  selection  of  key  actuarial  assumptions  utilized  in  the
     measurement of the plan obligations  drives the results of the analysis and
     the resulting charges. The long-term expected rate of return on plan assets
     (EROA)  assumption used in calculating  pension cost was 9.00% at August 1,
     2003 compared to 9.50% at December 31, 2002.  The EROA  assumption  used in
     calculating the other  postretirement  benefit obligation ranged from 7.52%
     to 8.68% at August 1, 2003  compared to 8.80% at December 31, 2002. A lower
     EROA is used in the  calculation of other  postretirement  benefit costs as
     the other postretirement  benefit trust activity is partially taxable while
     the pension trust  activity is  non-taxable.  The Moody's Aa Corporate Bond
     Index was used as a basis in selecting  the discount  rate,  using 6.60% at
     August 1, 2003  compared to 6.75% at December  31, 2002 in the  estimate of
     pension expense and other  postretirement  benefit costs.  The reduction in
     discount  rate is due to the  decline in Moody's  Aa  Corporate  Bond Index
     during 2003.

     Real Estate Tax Assessments (Exelon, PECO and Generation)
              PECO and Generation are challenging  real estate taxes assessed on
     nuclear  plants since 1997.  PECO is involved in  litigation in which it is
     contesting  Pennsylvania Public Utility Realty Tax Act of March 4, 1971, as
     amended  (PURTA) taxes  assessed in 1997 and has appealed local real estate
     assessments  for 1998 and 1999 on its formerly  owned  Limerick  Generating
     Station  (Montgomery  County,  PA) (Limerick) and Peach Bottom Atomic Power
     Station (York County, PA) (Peach Bottom) plants.  Generation is involved in
     real estate tax appeals for 2000 through 2003, also regarding the valuation
     of its Limerick  and Peach Bottom  plants,  its Quad Cities  Station  (Rock
     Island County,  IL) and, through its ownership  interest in AmerGen,  Three
     Mile Island (Dauphin County, PA).

              During  the third  quarter  of 2003,  upon  completion  of updated
     nuclear plant appraisal studies, PECO and Generation recorded reductions of
     $58  million  and $15  million,  respectively,  to  reserves  recorded  for
     exposures  associated with the real estate taxes. While PECO and Generation
     believe the resulting reserve balances as of September 30, 2003 reflect the
     most  likely  probable  expected  outcome  of the  litigation  and  appeals
     proceedings in accordance with SFAS No. 5, "Accounting for  Contingencies,"
     the ultimate outcome of such matters could result in additional unfavorable
     or favorable  adjustments to the consolidated  financial statements of PECO
     or Generation, and such adjustments could be material.

                                       75
<PAGE>

     Nuclear Decommissioning (Exelon and Generation)
              Generation  adopted SFAS No. 143, "Asset  Retirement  Obligations"
     (SFAS No.  143) on January 1, 2003.  SFAS No. 143  primarily  affected  the
     accounting  for the  decommissioning  of  Generation's  nuclear  generating
     plants  and  changed   the  method  used  to  report  the   decommissioning
     obligation.  Exelon and Generation recorded income of $112 million and $108
     million (net of income taxes),  respectively,  as a cumulative  effect of a
     change in accounting  principle in connection  with their adoptions of this
     standard in the first quarter of 2003.

              To  estimate  the fair  value of the  decommissioning  obligation,
     management  used a  probability-weighted,  discounted  cash flow model with
     multiple scenarios. Key assumptions used in the determination of fair value
     included  decommissioning  cost studies  prepared by a third party,  annual
     cost escalation studies to determine  escalation factors based on inflation
     indices,  and the  assignment of  probabilities  to various cost levels and
     various  timing  scenarios.  These timing  scenarios  incorporated  current
     license  lives and life  extensions  and the timing of Department of Energy
     (DOE)  acceptance  for  disposal  of  spent  nuclear  fuel.  The  estimated
     probability-weighted   cash  flows  using  these  various   scenarios  were
     discounted using credit-adjusted, risk-free rates applicable to the various
     businesses.  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.  Under SFAS No.  143,  the fair value of the nuclear
     decommissioning obligation will continue to be adjusted on an ongoing basis
     as the model input factors change.

     NEW ACCOUNTING PRONOUNCEMENTS

              See  Note  2 of  the  Condensed  Combined  Notes  to  Consolidated
     Financial Statements for discussion of new accounting pronouncements.

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

     RESULTS OF OPERATIONS

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

     Net Income and Earnings Per Share

              Exelon's net loss for the three months  ended  September  30, 2003
     was $102 million  compared to net income of $551 million in 2002.  Loss per
     diluted  common  share for the three months  ended  September  30, 2003 was
     $0.31  compared to income per diluted  share of $1.70 in 2002.  The overall
     decrease in income of $653 million  resulted from charges  recorded in 2003
     associated with the impairment of the long-lived  assets of EBG,  severance
     and related postretirement health and welfare benefits accruals and pension
     and postretirement  curtailment costs associated with The Exelon Way, and a
     decline  in the fair  value of  Generation's  investment  in  Sithe.  These
     charges were partially  offset by the reduction of property tax reserves at
     PECO and Generation and a gain recognized at Enterprises due to the sale of
     InfraSource during 2003.


                                       76
<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
     September 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 September 30,
                                                    --------------------------------
                                                              2003              2002         Variance          % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                       <C>              <C>                <C>               <C>
     Energy Delivery                                      $    303         $     370          $   (67)          (18.1%)
     Generation                                               (428)              163             (591)            n.m.
     Enterprises                                                16                15                1             6.7%
     Corporate                                                   7                 3                4           133.3%
     -------------------------------------------------------------------------------------------------
     Total                                                $  (102)         $     551          $  (653)         (118.5%)
     =================================================================================================
     n.m. - not meaningful
</TABLE>

     Results of Operations - Energy Delivery


<TABLE>
<CAPTION>
                                                             Three Months Ended September 30,
                                                             --------------------------------
      Energy Delivery                                                       2003         2002     Variance     % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                    <C>          <C>            <C>            <C>
     Operating revenues                                                $   2,886    $   3,162      $  (276)       (8.7%)
     Revenue, net of purchased power & fuel expense                        1,485        1,637         (152)       (9.3%)
     Operating income                                                        664          812         (148)      (18.2%)
     Income before income taxes                                              479          591         (112)      (19.0%)
     Net income                                                              303          370          (67)      (18.1%)
     -------------------------------------------------------------------------------------------------------------------
</TABLE>

              The changes in Energy Delivery's  revenue,  net of purchased power
     and fuel expense, for the three months ended September 30, 2003 compared to
     the same period in 2002, included the following:
          o    unfavorable weather impacts of $75 million,  primarily the result
               of cooler summer weather,
          o    unfavorable  variance  of $52  million due to changes in customer
               rates  due  to  lower   competitive   transition   charge   (CTC)
               collections at ComEd,
          o    unfavorable  rate  mix of $21  million  at  PECO as a  result  of
               changes in monthly usage patterns by all customer classes,
          o    unfavorable  pricing  changes of $20  million  related to ComEd's
               purchased power agreement (PPA) with Generation,


                                       77
<PAGE>

          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,  which had no impact on net
               income  as  these  amounts  were  recorded  in  depreciation  and
               amortization  expense  in  2002  (see  Note  2 of  the  Condensed
               Combined Notes to Consolidated Financial Statements),
          o    net  favorable  change of $8 million at ComEd as a result of 2002
               third-party energy reconciliations,
          o    lower PJM  ancillary  charges at PECO  resulting  in a  favorable
               variance of $4 million, and
          o    net favorable changes due to customer choice of $3 million.

              The changes in  operating  income,  other than changes in revenue,
     net of  purchased  power  and fuel  expense,  for the  three  months  ended
     September  30,  2003  compared  to the same  period in 2002,  included  the
     following:
          o    decreased costs of $67 million associated with PECO's real estate
               taxes, including a reduction of reserves for real estate taxes of
               $58 million in 2003,
          o    decreased payroll expense of $22 million due to fewer employees,
          o    lower amortization of ComEd's recoverable transition costs of $21
               million in 2003,
          o    a 2002 increase in the reserve for  manufactured  gas plant (MGP)
               investigation  and  remediation  of  $17  million,  net  of  2003
               increases,
          o    reduction  of  amortization  expense of $16  million at ComEd for
               nuclear  decommissioning of retired plants due to the adoption of
               SFAS  No.  143 (see  Note 2 of the  Condensed  Combined  Notes to
               Consolidated  Financial  Statements),  which had no impact on net
               income as these amounts were recorded as purchased power in 2003,
          o    decreased  costs  of $10  million  associated  with  the  initial
               implementation  of automated  meter  reading  services at PECO in
               2002,
          o    unfavorable variance of $101 million due to severance and related
               postretirement  health and welfare benefits  accruals and pension
               and  postretirement  curtailment costs associated with The Exelon
               Way,
          o    unfavorable  variance of $30 million due to higher  storm-related
               costs,
          o    unfavorable  variance  of  $9  million  due  to  employee  fringe
               benefits, and
          o    $8  million  in 2003 at ComEd for use tax  payments  for  periods
               prior to the merger of  Exelon,  Unicom  Corporation  and PECO on
               October 20, 2000 (Merger).

              The changes in other  income and  deductions  for the three months
     ended  September  30, 2003  compared to the same period in 2002  included a
     reduction  in  interest  expense  primarily  related to a  decrease  of $21
     million  attributable to less  outstanding debt and refinancing of existing
     debt at lower  interest rates and a reduction of $12 million as a result of
     a 2002 reserve  accrual for a potential  plant  disallowance  from an audit
     performed in conjunction with ComEd's delivery services rate case. This $12
     million  was  reversed  in March  2003 as a  result  of the  March 3,  2003
     agreement.  See the  Contractual  Obligations,  Commercial  Commitments and
     Off-Balance  Sheet  Obligations   section  below  for  further  information
     regarding the agreement.

              Energy  Delivery's  effective  income  tax rate was  36.7% for the
     three  months  ended  September  30,  2003,  compared to 37.4% for the same
     period in 2002.


                                       78
<PAGE>

     Energy Delivery Operating Statistics and Revenue Detail
              Energy  Delivery's  electric  sales  statistics and revenue detail
     were as follows:

<TABLE>
<CAPTION>
                                                            Three Months Ended September 30,
                                                            --------------------------------
     Retail Deliveries - (in gigawatthours (GWhs))(1)                       2003         2002     Variance     % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                       <C>          <C>          <C>          <C>
     Bundled Deliveries (2)
     Residential                                                          11,530       12,543       (1,013)      (8.1%)
     Small Commercial & Industrial                                         7,502        8,095         (593)      (7.3%)
     Large Commercial & Industrial                                         5,552        6,079         (527)      (8.7%)
     Public Authorities & Electric Railroads                               1,486        1,836         (350)     (19.1%)
     -----------------------------------------------------------------------------------------------------
        Total Bundled Deliveries                                          26,070       28,553       (2,483)      (8.7%)
     -----------------------------------------------------------------------------------------------------
     Unbundled Deliveries (3)
     Alternative Energy Suppliers
     ----------------------------
     Residential                                                             258          371         (113)     (30.5%)
     Small Commercial & Industrial                                         2,241        1,794          447       24.9%
     Large Commercial & Industrial                                         3,142        2,428          714       29.4%
     Public Authorities & Electric Railroads                                 426          299          127       42.5%
     -----------------------------------------------------------------------------------------------------
                                                                           6,067        4,892        1,175       24.0%
     -----------------------------------------------------------------------------------------------------
     PPO (ComEd Only)
     ----------------
     Small Commercial & Industrial                                           884          782          102       13.0%
     Large Commercial & Industrial                                           896        1,249         (353)     (28.3%)
     Public Authorities & Electric Railroads                                 428          345           83       24.1%
     -----------------------------------------------------------------------------------------------------
                                                                           2,208        2,376         (168)      (7.1%)
     -----------------------------------------------------------------------------------------------------
        Total Unbundled Deliveries                                         8,275        7,268        1,007       13.9%
     -----------------------------------------------------------------------------------------------------
     Total Retail Deliveries                                              34,345       35,821       (1,476)      (4.1%)
     =====================================================================================================
<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 Power
         Purchase Option (PPO).
</FN>
</TABLE>


                                       79
<PAGE>

<TABLE>
<CAPTION>
                                                            Three Months Ended September 30,
                                                            --------------------------------
     Electric Revenue                                                       2003         2002     Variance     % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                   <C>
     Bundled Revenues (1)
     Residential                                                       $   1,226    $   1,318    $     (92)      (7.0%)
     Small Commercial & Industrial                                           698          757          (59)      (7.8%)
     Large Commercial & Industrial                                           373          402          (29)      (7.2%)
     Public Authorities & Electric Railroads                                 102          125          (23)     (18.4%)
     -----------------------------------------------------------------------------------------------------
        Total Bundled Revenues                                             2,399        2,602         (203)      (7.8%)
     -----------------------------------------------------------------------------------------------------
     Unbundled Revenues (2)
     Alternative Energy Suppliers
     ----------------------------
     Residential                                                              20           32          (12)     (37.5%)
     Small Commercial & Industrial                                            62           60            2        3.3%
     Large Commercial & Industrial                                            46           67          (21)     (31.3%)
     Public Authorities & Electric Railroads                                   8           10           (2)     (20.0%)
     -----------------------------------------------------------------------------------------------------
                                                                             136          169          (33)     (19.5%)
     -----------------------------------------------------------------------------------------------------
     PPO (ComEd Only)
     ----------------
     Small Commercial & Industrial                                            65           57            8       14.0%
     Large Commercial & Industrial                                            56           74          (18)     (24.3%)
     Public Authorities & Electric Railroads                                  26           19            7       36.8%
     -----------------------------------------------------------------------------------------------------
                                                                             147          150           (3)      (2.0%)
     -----------------------------------------------------------------------------------------------------
        Total Unbundled Revenues                                             283          319          (36)     (11.3%)
     -----------------------------------------------------------------------------------------------------
     Total Electric Retail Revenues                                        2,682        2,921         (239)      (8.2%)
     -----------------------------------------------------------------------------------------------------
        Wholesale and Miscellaneous Revenue (3)                              151          174          (23)     (13.2%)
     -----------------------------------------------------------------------------------------------------
     Total Electric Revenue                                            $   2,833    $   3,095    $    (262)      (8.5%)
     =====================================================================================================
<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.
     (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  September  30,  2003 as  compared  to the same  period  in 2002 were
     attributable to the following:
                                                                      Variance
     --------------------------------------------------------------------------
     Weather                                                         $    (161)
     Rate changes                                                          (52)
     Customer choice                                                       (50)
     Rate mix                                                              (21)
     Volume                                                                 41
     Other effects                                                           4
     --------------------------------------------------------------------------
     Electric retail revenue                                         $    (239)
     ==========================================================================

     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 September 30, 2003 was unfavorable  compared to the
          same period in 2002 as a result of


                                       80
<PAGE>

          cooler summer  weather in 2003.  Cooling  degree-days in the ComEd and
          PECO service  territories were 25% lower and 11% lower,  respectively,
          in 2003 as compared to 2002.
     o    Rate Changes.  The decrease in revenues  attributable  to rate changes
          reflects decreased collections of $81 million in CTCs in 2003 by ComEd
          due to a  decrease  in CTC rates  effective  June 1,  2003,  partially
          offset  by higher  wholesale  market  prices  which  increased  energy
          revenue received under ComEd's PPO by $29 million.
     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 September 30,
          2003 and  2002,  18% and 14%,  respectively,  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 $36  million  from  customers  in  Illinois
          electing  to  purchase  energy  from an  alternative  retail  electric
          supplier  (ARES) or ComEd's  PPO,  and a decrease  in  revenues of $14
          million  from  customers  in  Pennsylvania  selecting  an  alternative
          electric generation supplier.
               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.  In
          September  2003,  the auction for the second phase of the  residential
          customer MST plan resulted in two winning  bidders who were awarded an
          aggregate  of  267,000  customers.  The  selected  customers  will  be
          transferred  during December 2003. No renewable bids were received for
          any  customers.  Any customer  transferred  has 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    Rate Mix.  Revenues  related to changes in rate mix at PECO  decreased
          $21 million due to changes in monthly  usage  patterns in all customer
          classes for the three months ended  September  30, 2003 as compared to
          the same period in 2002.

                                       81
<PAGE>


     o    Volume.  Revenues from higher delivery sales,  exclusive of the effect
          of weather,  increased $40 million at ComEd due to an increased number
          of customers and increased usage per customer,  primarily  residential
          and small  commercial and  industrial.  Revenues from delivery  sales,
          exclusive of the effect of weather, increased $1 million at PECO.

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

<TABLE>
<CAPTION>
                                                             Three Months Ended September 30,
                                                             --------------------------------
     Deliveries to customers in million cubic feet (mmcf)                   2003         2002     Variance     % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                        <C>          <C>           <C>        <C>
     Retail sales                                                          3,498        3,805         (307)      (8.1%)
     Transportation                                                        6,012        7,542       (1,530)     (20.3%)
     -----------------------------------------------------------------------------------------------------
     Total                                                                 9,510       11,347       (1,837)     (16.2%)
     =====================================================================================================

                                                             Three Months Ended September 30,
                                                             --------------------------------
     Revenue                                                                2003         2002     Variance     % Change
     -------------------------------------------------------------------------------------------------------------------
     Retail sales                                                      $      47    $      43    $       4        9.3%
     Transportation                                                            4            5           (1)     (20.0%)
     Resales and other                                                         2           19          (17)     (89.5%)
     -----------------------------------------------------------------------------------------------------
     Total                                                             $      53     $     67    $     (14)     (20.9%)
     =====================================================================================================
</TABLE>

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

<TABLE>
<CAPTION>
                                                                                                               Variance
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                                                           <C>
     Rate changes                                                                                             $       6
     Volume                                                                                                          (2)
     -------------------------------------------------------------------------------------------------------------------
     Total gas retail revenues                                                                                $       4
     ===================================================================================================================
</TABLE>

     o    Rate Changes.  The favorable  variance in rate changes is attributable
          to increases of 15% and 7% 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  September 30,
          2003 was 18% 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.

     o    Volume.  Delivery volume was lower in the three months ended September
          30, 2003  compared to the same period in 2002 due to decreased  retail
          sales in all customer classes.

              The reduction in transportation volumes and revenues was primarily
     the result of lower intercompany  deliveries to Generation during the three
     months ended September 30, 2003 compared to the same period in 2002.

                                       82
<PAGE>


              Lower resale revenues are attributable to a decrease in off-system
     sales,  exchanges  and  capacity  releases  during the three  months  ended
     September 30, 2003 compared to the same period in 2002.


     Results of Operations - Generation

<TABLE>
<CAPTION>
                                                             Three Months Ended September 30,
                                                             --------------------------------
                                                                            2003         2002     Variance     % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                    <C>          <C>            <C>            <C>
     Operating revenues                                                $   2,537    $   2,213      $   324        14.6%
     Revenue, net of purchased power & fuel expense                          848          683          165        24.2%
     Operating income (loss)                                                (706)         187         (893)        n.m.
     Income (loss) before income taxes                                      (708)         265         (973)        n.m.
     Net income (loss)                                                      (428)         163         (591)        n.m.
     -------------------------------------------------------------------------------------------------------------------
     n.m. - not meaningful
</TABLE>

              The changes in  Generation's  revenue,  net of purchased power and
     fuel expense, for the three months ended September 30, 2003 compared to the
     same period in 2002, included the following:
     o    increased  market  sales  of  electricity  of $167  million  primarily
          attributable  to  regional  demand  and  higher  prices,  and  reduced
          capacity payments as a result of releasing Midwest Generation options,
     o    unfavorable   weather   conditions  in  the  ComEd  and  PECO  service
          territories  in 2003  resulted  in a net  volume  decrease,  partially
          offset by price  increases,  resulting in a $121  million  unfavorable
          variance on revenues from Energy Delivery,
     o    increased decommissioning revenue from ComEd of $16 million associated
          with the  adoption of SFAS No.  143,  which was  effective  January 1,
          2003,
     o    mark-to-market  losses on hedging  activities  of $18  million in 2003
          compared to no gains or losses in 2002, and
     o    increases  of $13 million as a result of reduced  proprietary  trading
          activity and overall trade portfolio performance.

              Other significant factors affecting the changes in revenue, net of
     purchased power and fuel, include the impacts of the plants acquired during
     2002 resulting in a net favorable variance of $60 million. In addition, the
     impacts of lower volumes of purchased power, which were partially offset by
     higher fuel costs, resulted in a net favorable impact of $49 million.

              The changes in  operating  income  (loss),  other than  changes in
     revenue,  net of  purchased  power and fuel  expense,  for the three months
     ended September 30, 2003 compared to the same period in 2002,  included the
     following:
     o    impairment  charge of $945 million related to the long-lived assets of
          EBG,
     o    $46 million in severance and related postretirement health and welfare
          benefits  accruals and pension and  postretirement  curtailment  costs
          associated with The Exelon Way,
     o    higher  costs of $15 million for employee  medical,  pension and other
          employee payroll and benefit costs in 2003,
     o    increased  operating and maintenance (O&M) costs of $30 million due to
          the acquisition of Exelon New England in the fourth quarter of 2002,


                                       83
<PAGE>

     o    reduced  refueling  outage costs of $9 million,  resulting  from fewer
          total refueling outage days in 2003,
     o    additional depreciation of $17 million due to capital additions placed
          in service  and plant  acquisitions  made  after the third  quarter of
          2002,
     o    accretion  expense of $60 million  recognized  in 2003 to increase the
          asset  retirement  obligation  established at the adoption of SFAS No.
          143,  and 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, partially offset by the
          elimination  of  decommissioning  expense  of $29  million,  also as a
          result of the  adoption  of SFAS No. 143 (see Note 2 of the  Condensed
          Combined  Notes  to  Consolidated  Financial  Statements  for  further
          discussion of SFAS No. 143), and
     o    decreased  property  taxes of $15 million as a result of reductions in
          reserves  in  the  third   quarter  of  2003  recorded  for  exposures
          associated with real estate taxes.

              The changes in other  income and  deductions  for the three months
     ended September 30, 2003 compared to the same period in 2002,  included the
     following:
     o    impairment charge of $55 million related to Generation's investment in
          Sithe,
     o    increased decommissioning trust investment income of $9 million, which
          is almost entirely offset by accretion  expense,  net of depreciation,
          recorded in O&M, and
     o    decreased  equity in  earnings  of  unconsolidated  affiliates  of $34
          million due to the  purchase  of Exelon New England in November  2002,
          the negative  impacts of power  trading  activity at Sithe and reduced
          earnings from AmerGen.

              Generation's  effective  income  tax rate was  39.5% for the three
     months ended  September  30, 2003  compared to 38.5% for the same period in
     2002. This increase was primarily  attributable to the impact of changes in
     income before income taxes as a result of the impairment  charges  recorded
     in the third  quarter of 2003 related to  Generation's  investment in Sithe
     and the long-lived assets of EBG.

                                       84
<PAGE>

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

<TABLE>
<CAPTION>
                                                             Three Months Ended September 30,
                                                             --------------------------------
     Sales (in GWhs)                                                        2003         2002     Variance     % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                       <C>          <C>          <C>         <C>
     Energy Delivery and Exelon Energy Company                            32,237       35,996       (3,759)     (10.4%)
     Market Sales                                                         29,613       21,177        8,436       39.8%
     -----------------------------------------------------------------------------------------------------
     Total Sales                                                          61,850       57,173        4,677        8.2%
     =====================================================================================================

                                                             Three Months Ended September 30,
                                                             --------------------------------
     Supply of Sales (in GWhs)                                              2003         2002     Variance     % Change
     -------------------------------------------------------------------------------------------------------------------
     Nuclear Generation (1)                                               30,152       29,817          335        1.1%
     Purchases - non-trading portfolio (2)                                24,062       23,425          637        2.7%
     Fossil and Hydro Generation                                           7,636        3,931        3,705       94.3%
     -----------------------------------------------------------------------------------------------------
     Total Supply                                                         61,850       57,173        4,677        8.2%
     =====================================================================================================
<FN>
     (1) Excluding AmerGen.
     (2) Including PPAs with AmerGen.
</FN>
</TABLE>

              Trading  volumes  of  11,086  GWhs and  28,455  GWhs for the three
     months ended September 30, 2003 and 2002, respectively, are not included in
     the table  above.  The  decrease  in trading  volume is a result of reduced
     volumetric and Value-at-Risk (VaR) trading limits in 2003, which are set by
     Exelon's Risk Management Committee and approved by the Board of Directors.

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

<TABLE>
<CAPTION>
                                                                       Three Months Ended September 30,
                                                                       --------------------------------
      ($/MWh)                                                                   2003               2002        % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                      <C>              <C>                     <C>
     Average Revenue
         Energy Delivery and Exelon Energy Company                       $     41.51      $      40.56            2.3%
         Market Sales                                                          38.43             35.50            8.3%
         Total - excluding the trading portfolio                               40.03             38.69            3.5%

     Average Supply Cost (1) - excluding the trading portfolio           $     27.31      $      26.66            2.4%

     Average Margin - excluding the trading portfolio                    $     12.72      $      12.04            5.6%
     -----------------------------------------------------------------------------------------------------------------
<FN>
     (1) Average supply cost includes purchased power and fuel costs.
     (2) Including PPAs with AmerGen.
</FN>
</TABLE>

<TABLE>
<CAPTION>
                                                                                       Three Months Ended September 30,
                                                                                       --------------------------------
                                                                                                   2003            2002
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                                         <C>             <C>
     Nuclear fleet capacity factor (1)                                                             95.3%           93.9%
     Nuclear fleet production cost per MWh (1)                                               $    11.69       $   12.40
     Average purchased power cost for wholesale operations per MWh (2)                       $    51.53       $   53.75
     -------------------------------------------------------------------------------------------------------------------
<FN>
     (1)  Including  AmerGen and  excluding  Salem,  which is operated by Public
          Service Enterprise Group Incorporated (PSE&G).
     (2)  Including PPAs with AmerGen.
</FN>
</TABLE>

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

                                       85
<PAGE>


              Generation's average revenue per MWh was affected by:
     o    higher market prices as a result of increased fuel prices, and
     o    increased  weighted  average on and off-peak prices per MWh for supply
          agreements with ComEd and PECO.

              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 3,570 GWhs, and
     o    a new PPA with AmerGen entered into during the second quarter of 2003,
          resulting in 1,228 GWhs purchased from Oyster Creek Nuclear Generating
          Station (Oyster Creek) in the third quarter of 2003.

              Higher nuclear capacity factors and decreased  nuclear  production
     costs  are  primarily  due  to 16  fewer  planned  refueling  outage  days,
     resulting  in a $9 million  decrease in outage  costs,  in the three months
     ended  September 30, 2003 as compared to the same period in 2002. The three
     months ended September 30, 2003 included nine unplanned outages compared to
     seven unplanned outages during the three months ended September 30, 2002.


     Results of Operations - Enterprises

<TABLE>
<CAPTION>
                                                             Three Months Ended September 30,
                                                             --------------------------------
                                                                            2003         2002     Variance     % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                      <C>          <C>          <C>          <C>
     Operating revenues                                                  $   437      $   509      $   (72)     (14.1%)
     Operating income                                                         24           15            9       60.0%
     Income before income taxes                                               26           20            6       30.0%
     Net income                                                               16           15            1        6.7%
     -------------------------------------------------------------------------------------------------------------------
</TABLE>

              The changes in Enterprises'  operating income for the three months
     ended September 30, 2003 compared to the same period in 2002,  included the
     following:
     o    a gain on sale of $44  million,  net of  transaction  costs and before
          income  taxes,  related to the sale of the electric  construction  and
          services, underground and telecom businesses of InfraSource,
     o    lower  operating  income  at  InfraSource  of  $21  million  primarily
          resulting from a decrease in the electric  business of $26 million and
          a decrease in the underground business of $2 million, partially offset
          by lower  depreciation of $8 million as a result of the classification
          of InfraSource's property, plant and equipment as held for sale in the
          second quarter of 2003,
     o    lower  operating  income at Exelon  Services of $2 million,  primarily
          resulting from reduced construction projects,
     o    lower  operating  income  at  Exelon  Energy  Company  of  $4  million
          primarily resulting from the reversal of mark-to-market adjustments of
          $1 million and  additional  gas supply  costs and  business  wind-down
          costs of $4 million  for  Northeast  operations,  partially



                                       86
<PAGE>

          offset  by  higher  gross   margins  of  $2  million  in  the  Midwest
          attributable to increased unit margins and higher volumes, and
     o    higher allocated O&M costs of $6 million.

         The change in other  income and  deductions  for the three months ended
     September 30, 2003 compared to the same period in 2002 was primarily due to
     lower  equity  in  earnings  of  unconsolidated  affiliates  of $9  million
     primarily  resulting  from the recovery of trade  receivables  in 2002 that
     were previously considered uncollectible at a communications joint venture.

              The effective income tax rate was 38.5% for the three months ended
     September  30,  2003,  compared to 25.0% for the same  period in 2002.  The
     increase  in  the  effective  tax  rate  was  primarily  attributable  to a
     reduction  in estimated  state income tax recorded  during the three months
     ended September 30, 2002.

     Nine Months Ended  September  30, 2003 and Nine Months Ended  September 30,
     2002

     Net Income and Earnings Per Share

              Exelon's net income for the nine months ended  September  30, 2003
     decreased $412 million or 40%, compared to the same period in 2002. Diluted
     earnings per common share on the same basis decreased $1.29 per share.  Net
     income for the nine months ended  September  30, 2003 reflects $112 million
     of income for the cumulative effect of a change in accounting  principle as
     a result of the  adoption  of SFAS No.  143 while net  income  for the nine
     months ended  September  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 nine months  ended  September  30, 2003  decreased  $754
    million,  or 59%, compared to the same period in 2002.  Diluted earnings per
    common share on the same basis  decreased  $2.34 per share.  The decrease in
    income before cumulative effect of changes in accounting principles reflects
    an  impairment  of the  long-lived  assets of EBG recorded  during the third
    quarter of 2003,  impairment  charges related to Generation's  investment in
    Sithe  recorded in the first and third  quarters of 2003 and  severance  and
    related  postretirement health and welfare benefits accruals and pension and
    post-employment  curtailment  costs  associated  with The Exelon Way.  These
    reductions  in income were  partially  offset by  reductions in property tax
    reserves at PECO and Generation during the third quarter of 2003,  increased
    energy margins at Generation due to the acquisition of Exelon New England in
    November  2002 and  decreased  interest  expense at Energy  Delivery  due to
    refinancing of outstanding  debt at lower interest  rates.  Additionally,  a
    gain  was  recorded  in the  second  quarter  of 2002  due to the sale of an
    investment in AT&T Wireless held by Enterprises.


                                       87
<PAGE>

     Results of Operations by Business Segment

              The  comparisons  presented  under this heading are comparisons of
     operating  results and other  statistical  information  for the nine months
     ended  September  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.

     Net  Income  (Loss)  Before  Cumulative  Effect of  Changes  in  Accounting
     Principles by Business Segment

<TABLE>
<CAPTION>
                                                     Nine Months Ended September 30,
                                                     -------------------------------
                                                              2003              2002         Variance          % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                       <C>              <C>                <C>                 <C>
     Energy Delivery                                      $    920         $     908          $    12             1.3%
     Generation                                               (339)              313             (652)         n.m.
     Enterprises                                               (62)               69             (131)         (189.9%)
     Corporate                                                  --               (17)              17          (100.0%)
     -------------------------------------------------------------------------------------------------
     Total                                                $    519         $   1,273          $  (754)          (59.2%)
     =================================================================================================
<FN>
     n.m. - not meaningful
</FN>
</TABLE>

     Net Income (Loss) by Business Segment

<TABLE>
<CAPTION>
                                                     Nine Months Ended September 30,
                                                     -------------------------------
                                                              2003              2002         Variance          % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                       <C>              <C>                <C>                 <C>
     Energy Delivery                                      $    925         $     908          $    17             1.9%
     Generation                                               (231)              326             (557)         (170.9%)
     Enterprises                                               (63)             (174)             111           (63.8%)
     Corporate                                                  --               (17)              17          (100.0%)
     -------------------------------------------------------------------------------------------------
     Total                                                $    631         $   1,043          $  (412)          (39.5%)
     =================================================================================================
</TABLE>


     Results of Operations - Energy Delivery

<TABLE>
<CAPTION>
                                                              Nine Months Ended September 30,
                                                              -------------------------------
      Energy Delivery                                                       2003         2002     Variance     % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                    <C>          <C>            <C>            <C>
     Operating revenues                                                $   7,850    $   7,973      $  (123)       (1.5%)
     Revenue, net of purchased power & fuel expense                        4,274        4,414         (140)       (3.2%)
     Operating income                                                      2,025        2,108          (83)       (3.9%)
     Income before income taxes and cumulative effect of a
       change in accounting principle                                      1,478        1,455           23         1.6%
     Income before cumulative effect of a change in
       accounting principle                                                  920          908           12         1.3%
     Net income                                                              925          908           17         1.9%
     -------------------------------------------------------------------------------------------------------------------
</TABLE>

              The changes in Energy Delivery's  revenue,  net of purchased power
     and fuel expense,  for the nine months ended September 30, 2003 compared to
     the same period in 2002, included the following:
     o    net unfavorable  weather impacts of $63 million,  primarily the result
          of cooler summer weather partially offset by colder winter weather,
     o    unfavorable pricing changes of $60 million related to ComEd's PPA with
          Generation,
     o    unfavorable   variance  of  $47  million  under  the  ComEd  PPA  with
          Generation related to decommissioning  collections associated with the
          adoption of SFAS No. 143 in 2003,

                                       88
<PAGE>

          which had no impact on net income as these  amounts  were  recorded in
          depreciation  and  amortization  expense  in 2002  (see  Note 2 of the
          Condensed Combined Notes to Consolidated Financial Statements),
     o    unfavorable  rate mix  variance  of $28 million at PECO as a result of
          changes in monthly usage patterns by all customer classes,
     o    net  unfavorable  changes  due to  customer  choice  of  $25  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    increases in weather  normalized volumes of $32 million as a result of
          increases in the number of customers and additional  average usage per
          customer,  primarily  residential and small  commercial and industrial
          customers  at ComEd,  and small and large  commercial  and  industrial
          customers at PECO,
     o    favorable variance of $23 million due to changes in customer rates due
          to additional CTC collections at ComEd, and
     o    net  favorable  change  of $8  million  at ComEd  as a result  of 2002
          third-party energy reconciliations.

              The changes in  operating  income,  other than changes in revenue,
     net of  purchased  power  and  fuel  expense,  for the  nine  months  ended
     September  30,  2003  compared  to the same  period in 2002,  included  the
     following:
     o    a decrease in real estate  taxes at PECO of $70  million,  including a
          reduction of $58 million of reserves for real estate taxes in 2003,
     o    decreased payroll expense of $64 million due to fewer employees,
     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 $24 million due to
          higher plant in service balances,
     o    reduction  of   amortization   expense  of  $47  million  for  nuclear
          decommissioning of retired plants at ComEd due to the adoption of SFAS
          No.  143,  which  had no impact on net  income as these  amounts  were
          recorded  as  purchased  power in 2003  (see  Note 2 of the  Condensed
          Combined Notes to Consolidated Financial Statements),
     o    lower  amortization  of ComEd's  recoverable  transition  costs of $41
          million in 2003,
     o    decreased   costs  of  $23   million   associated   with  the  initial
          implementation of automated meter reading services at PECO in 2002,
     o    decreased  costs of $12 million in the  reserve for MGP  investigation
          and remediation in 2002 net of 2003 increases,
     o    a reversal of $12 million of accrued use tax at PECO as a result of an
          audit settlement,
     o    unfavorable  variance  of $101  million due to  severance  and related
          postretirement health and welfare benefits  accruals and  pension  and
          postretirement curtailment costs associated with The Exelon Way,
     o    unfavorable variance of $35 million due to higher storm-related costs,
     o    a net one-time charge of $41 million in 2003 at ComEd as the result of
          an  agreement  described  in Note 5 of  Condensed  Combined  Notes  to
          Consolidated Financial Statements,
     o    unfavorable  variance of $28 million due to employee fringe  benefits,
          and
     o    additional  amortization  in 2003 of $20  million  at PECO  related to
          PECO's CTC in accordance with the Pennsylvania Competitive Act.

                                       89
<PAGE>

              The  changes in other  income and  deductions  for the nine months
     ended September 30, 2003 compared to the same period in 2002,  included the
     following:
     o    a reduction in interest expense primarily related to a decrease of $66
          million  attributable  to less  outstanding  debt and  refinancing  of
          existing debt at lower interest rates, and
     o    a reduction of $12 million as a result of a 2002 reserve accrual for a
          potential  plant  disallowance  from an audit performed in conjunction
          with ComEd's delivery  services rate case, and the reversal in 2003 of
          this reserve as the result of an agreement  described in Note 5 of the
          Condensed Combined Notes to Consolidated Financial Statements.

              Energy Delivery's effective income tax rate was 37.8% for the nine
     months ended  September 30, 2003,  compared to 37.6% 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.

     Energy Delivery Operating Statistics and Revenue Detail
              Energy  Delivery's  electric  sales  statistics and revenue detail
     were as follows:

<TABLE>
<CAPTION>
                                                             Nine Months Ended September 30,
                                                             -------------------------------
     Retail Deliveries - (GWhs)                                             2003         2002     Variance     % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                       <C>          <C>            <C>        <C>
     Bundled Deliveries (1)
     Residential                                                          28,969       28,984          (15)      (0.1%)
     Small Commercial & Industrial                                        21,555       22,782       (1,227)      (5.4%)
     Large Commercial & Industrial                                        15,896       17,436       (1,540)      (8.8%)
     Public Authorities & Electric Railroads                               4,710        5,715       (1,005)     (17.6%)
     -----------------------------------------------------------------------------------------------------
        Total Bundled Deliveries                                          71,130       74,917       (3,787)      (5.1%)
     -----------------------------------------------------------------------------------------------------
     Unbundled Deliveries (2)
     Alternative Energy Suppliers
     ----------------------------
     Residential                                                             708        1,720       (1,012)     (58.8%)
     Small Commercial & Industrial                                         5,371        4,075        1,296       31.8%
     Large Commercial & Industrial                                         7,504        5,551        1,953       35.2%
     Public Authorities & Electric Railroads                                 954          618          336       54.4%
     -----------------------------------------------------------------------------------------------------
                                                                          14,537       11,964        2,573       21.5%
     -----------------------------------------------------------------------------------------------------
     PPO (ComEd Only)
     ----------------
     Small Commercial & Industrial                                         2,546        2,384          162        6.8%
     Large Commercial & Industrial                                         3,646        3,952         (306)      (7.7%)
     Public Authorities & Electric Railroads                               1,497          861          636       73.9%
     -----------------------------------------------------------------------------------------------------
                                                                           7,689        7,197          492        6.8%
     -----------------------------------------------------------------------------------------------------
        Total Unbundled Deliveries                                        22,226       19,161        3,065       16.0%
     -----------------------------------------------------------------------------------------------------
     Total Retail Deliveries                                              93,356       94,078         (722)      (0.8%)
     =====================================================================================================
<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>


                                       90
<PAGE>

<TABLE>
<CAPTION>
                                                             Nine Months Ended September 30,
                                                             -------------------------------
     Electric Revenue                                                       2003         2002     Variance     % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                    <C>          <C>          <C>              <C>
     Bundled Revenues (1)
     Residential                                                       $   2,899    $   2,880    $      19        0.7%
     Small Commercial & Industrial                                         1,874        2,007         (133)      (6.6%)
     Large Commercial & Industrial                                         1,065        1,152          (87)      (7.6%)
     Public Authorities & Electric Railroads                                 309          356          (47)     (13.2%)
     -----------------------------------------------------------------------------------------------------
        Total Bundled Revenues                                             6,147        6,395         (248)      (3.9%)
     -----------------------------------------------------------------------------------------------------
     Unbundled Revenues (2)
     Alternative Energy Suppliers
     ----------------------------
     Residential                                                              52          129          (77)     (59.7%)
     Small Commercial & Industrial                                           161          107           54        50.5%
     Large Commercial & Industrial                                           149          111           38        34.2%
     Public Authorities & Electric Railroads                                  25           18            7        38.9%
     -----------------------------------------------------------------------------------------------------
                                                                             387          365           22        6.0%
     -----------------------------------------------------------------------------------------------------
     PPO (ComEd Only)
     ----------------
     Small Commercial & Industrial                                           174          155           19       12.3%
     Large Commercial & Industrial                                           199          214          (15)      (7.0%)
     Public Authorities & Electric Railroads                                  81           48           33       68.8%
     -----------------------------------------------------------------------------------------------------
                                                                             454          417           37        8.9%
     -----------------------------------------------------------------------------------------------------
        Total Unbundled Revenues                                             841          782           59        7.5%
     -----------------------------------------------------------------------------------------------------
     Total Electric Retail Revenues                                        6,988        7,177         (189)      (2.6%)
     -----------------------------------------------------------------------------------------------------
        Wholesale and Miscellaneous Revenue (3)                              414          438          (24)      (5.5%)
     -----------------------------------------------------------------------------------------------------
     Total Electric Revenue                                            $   7,402    $   7,615    $    (213)      (2.8%)
     =====================================================================================================
<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 nine months
     ended  September  30,  2003 as  compared  to the same  period  in 2002 were
     attributable to the following:

<TABLE>
<CAPTION>
                                                                                                               Variance
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                                                           <C>
     Weather                                                                                                  $    (189)
     Customer choice                                                                                               (116)
     Rate mix                                                                                                       (28)
     Volume                                                                                                         109
     Rate changes                                                                                                    23
     Other effects                                                                                                   12
     -------------------------------------------------------------------------------------------------------------------
     Electric retail revenue                                                                                  $    (189)
     ===================================================================================================================
</TABLE>

     o    Weather.  The weather  impact for the nine months ended  September 30,
          2003 was  unfavorable  compared to the same period in 2002 as a result
          of cooler summer  weather in 2003,  partially  offset by colder winter
          weather. Cooling degree-days in the ComEd and

                                       91
<PAGE>

          PECO service  territories were 36% lower and 19% lower,  respectively,
          in 2003 as compared to 2002. Heating degree-days in the ComEd and PECO
          service territories were 15% higher and 35% higher,  respectively,  in
          2003 as compared to 2002.
     o    Customer  Choice.  For the nine months  ended  September  30, 2003 and
          September 30, 2002, 16% and 13%, respectively,  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 $113  million  from  customers  in Illinois
          electing  to  purchase  energy  from  an ARES or  ComEd's  PPO,  and a
          decrease in  revenues of $3 million  from  customers  in  Pennsylvania
          selecting and alternative electric generation supplier.
     o    Rate Mix.  Revenues  related to changes in rate mix at PECO  decreased
          $28 million due to changes in monthly  usage  patterns in all customer
          classes for the nine months ended  September  30, 2003 as compared to
          the same period in 2002.
     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 and small
          commercial and industrial  customer classes for ComEd and in the small
          and large commercial and industrial customer classes for PECO.
     o    Rate Changes.  The increase in revenues  attributable  to rate changes
          reflects the  collection of  additional  CTCs in 2003 by ComEd through
          June 1, 2003, offset by lower collections since then. The net increase
          for the nine months ended September 30, 2003 was $65 million. Starting
          in the June 2003 billing cycle,  the increased  wholesale market price
          of electricity,  net of increased  mitigation  factors, as a result of
          an agreement  described in  Note 5 of the Condensed  Combined Notes to
          Consolidated  Financial Statements,  decreased the collections of CTCs
          as compared to the respective  period in 2002 by $81 million.  Changes
          in wholesale  market prices  decreased  energy revenue  received under
          ComEd's PPO by $42 million.

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

<TABLE>
<CAPTION>
                                                              Nine Months Ended September 30,
                                                              -------------------------------
     Deliveries to customers in mmcf                                        2003         2002     Variance     % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                       <C>          <C>          <C>          <C>
     Retail sales                                                         44,183       34,128       10,055       29.5%
     Transportation                                                       19,954       22,862       (2,908)     (12.7%)
     -----------------------------------------------------------------------------------------------------
     Total                                                                64,137       56,990        7,147       12.5%
     =====================================================================================================
     n.m. - not meaningful
                                                              Nine Months Ended September 30,
                                                              -------------------------------
     Revenue                                                                2003         2002     Variance     % Change
     -------------------------------------------------------------------------------------------------------------------
     Retail sales                                                      $     418    $     309    $     109       35.3%
     Transportation                                                           14           15           (1)      (6.7%)
     Resales and other                                                        16           34          (18)     (52.9%)
     -----------------------------------------------------------------------------------------------------
     Total                                                             $     448     $    358     $     90       25.1%
     =====================================================================================================
</TABLE>


                                       92
<PAGE>

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

<TABLE>
<CAPTION>
                                                                                                               Variance
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                                                           <C>
     Weather                                                                                                  $      73
     Volume                                                                                                          21
     Rate changes                                                                                                    15
     -------------------------------------------------------------------------------------------------------------------
     Total gas retail revenue                                                                                 $     109
     ===================================================================================================================
</TABLE>

     o    Weather.  The weather impact was favorable  compared to the prior year
          as a result of colder winter weather.  Heating  degree-days  increased
          35% in the nine months ended  September  30, 2003 compared to the same
          period in 2002. Retail sales deliveries increased  approximately 8,600
          mmcf due to the colder weather.
     o    Volume. Exclusive of weather impacts, higher delivery volume increased
          revenue in the nine months ended  September  30, 2003  compared to the
          same  period in 2002  resulting  from  increased  retail  sales in all
          classes.  Deliveries to retail customers increased approximately 1,500
          mmcf,  or 4% in the nine months ended  September  30, 2003 compared to
          the same period in 2002.
     o    Rate  Changes.  The  favorable  variance in rates is  attributable  to
          increases of 15% and 7% in the  purchased  gas  adjustment  by the PUC
          effective  March 1, 2003 and June 1, 2003,  respectively.  The average
          rate per mmcf for the nine  months  ended  September  30,  2003 was 5%
          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.

              The reduction in transportation volumes and revenues was primarily
     the result of lower  intercompany  deliveries to Generation during the nine
     months ended September 30, 2003 compared to the same period in 2002.

              Lower resale revenues are attributable to a decrease in off-system
     sales,  exchanges  and  capacity  releases  during  the nine  months  ended
     September 30, 2003 compared to the same period in 2002.

                                       93
<PAGE>

     Results of Operations - Generation
<TABLE>
<CAPTION>
                                                              Nine Months Ended September 30,
                                                              -------------------------------
                                                                            2003         2002     Variance     % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                    <C>          <C>            <C>            <C>
     Operating revenues                                                $   6,301    $   5,233      $ 1,068        20.4%
     Revenue, net of purchased power & fuel expense                        2,264        1,946          318        16.3%
     Operating income (loss)                                                (411)         389         (800)     n.m.
     Income (loss) before income taxes and cumulative effect
       of changes in accounting principles                                  (548)         511       (1,059)     n.m.
     Income (loss) before cumulative effect of changes in
       accounting principles                                                (339)         313         (652)     n.m.
     Net income (loss)                                                      (231)         326         (557)     (170.9%)
     -------------------------------------------------------------------------------------------------------------------
<FN>
     n.m. - not meaningful
</FN>
</TABLE>

              The changes in  Generation's  revenue,  net of purchased power and
     fuel expense,  for the nine months ended September 30, 2003 compared to the
     same period in 2002, included the following:
     o    increased  market  sales of $593  million  primarily  attributable  to
          higher  regional  demand  and  higher  prices,  and  reduced  capacity
          payments as a result of releasing Midwest Generation options,
     o    unfavorable   weather   conditions  in  the  ComEd  and  PECO  service
          territories  in 2003  resulted  in a net  volume  decrease,  partially
          offset by price  increases,  resulting in a $112  million  unfavorable
          variance on revenue from Energy Delivery,
     o    increased decommissioning revenue from ComEd of $47 million associated
          with the  adoption of SFAS No. 143,  which was not included in revenue
          in 2002,
     o    mark-to-market  losses on hedging  activities  of $17  million in 2003
          compared to a gain of $11 million in 2002,
     o    favorable  changes in trade book activity of $26 million were a result
          of lower losses from  decreased  trading  volumes in 2003  compared to
          2002, and
     o    additional  nuclear fuel amortization of $16 million in 2003 resulting
          from under performing fuel at the Quad Cities Unit 1.

              Other significant factors affecting the changes in revenue, net of
     purchased power and fuel, include the impacts of the plants acquired during
     2002  resulting in a net favorable  variance of $111 million.  In addition,
     the impacts of higher prices of purchased  power and fuel costs,  partially
     offset by lower volumes of purchased  power,  resulted in a net unfavorable
     impact of $301 million.

              The changes in  operating  income  (loss),  other than  changes in
     revenue, net of purchased power and fuel expense, for the nine months ended
     September  30,  2003  compared  to the same  period in 2002,  included  the
     following:
     o    impairment  charge of $945 million related to the long-lived assets of
          EBG,
     o    increased  accretion  expense of $162  million due to the  adoption of
          SFAS No. 143, partially offset by reduced  decommissioning  expense of
          $93 million,
     o    higher  costs of $51 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,

                                       94
<PAGE>

     o    increased  O&M costs of $68  million  due to asset  acquisitions  made
          during 2002 and a $5 million asset impairment  charge recorded in 2003
          related to Mystic Station Units 4, 5, and 6,
     o    $46 million in severance and related postretirement health and welfare
          benefits  accruals and pension and  postretirement  curtailment  costs
          associated with The Exelon Way,
     o    reduced  refueling outage costs of $61 million,  including $17 million
          at one of  Generation's  co-owned  facilities,  resulting  from  fewer
          refueling outage days in 2003,
     o    additional depreciation of $39 million due to capital additions placed
          in service and plant acquisitions made during 2002 and $13 million due
          to plant acquisitions made after the third quarter of 2002,  partially
          offset by a $12 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 other  income and  deductions  for the nine months
     ended September 30, 2003 compared to the same period in 2002,  included the
     following:
     o    impairment  charges of $255  million  related to  Generation's  equity
          investment in Sithe,
     o    increased  decommissioning  trust  investment  income of $41  million,
          which  is  almost  entirely  offset  with  accretion  expense,  net of
          depreciation, recorded in O&M,
     o    decreased  equity in  earnings  of  unconsolidated  affiliates  of $29
          million and
     o    increased  interest expense of $12 million primarily due to $8 million
          of interest  expense on the  long-term  debt  assumed as a part of the
          Exelon New England asset acquisition,  reduced capitalized interest in
          2003,  and $7  million of  interest  incurred  on the note  payable to
          Sithe.

              Generation's  effective  income  tax rate was  38.1%  for the nine
     months ended  September  30, 2003  compared to 38.7% for the same period in
     2002. This decrease was primarily  attributable to the impact of changes in
     income  before  taxes  as a  result  of  the  impairments  of  Generation's
     investment in Sithe and the long-lived assets of EBG.

              Cumulative effect of changes in accounting  principles recorded in
     the nine months ended  September 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.

                                       95
<PAGE>

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

<TABLE>
<CAPTION>
                                                              Nine Months Ended September 30,
                                                              -------------------------------
     Sales (in GWhs)                                                        2003         2002     Variance     % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                       <C>          <C>          <C>          <C>
     Energy Delivery and Exelon Energy Company                            89,700       94,646       (4,946)      (5.2%)
     Market Sales                                                         80,877       61,089       19,788       32.4%
     -----------------------------------------------------------------------------------------------------
     Total Sales                                                         170,577      155,735       14,842        9.5%
     =====================================================================================================

                                                              Nine Months Ended September 30,
                                                              -------------------------------
     Supply of Sales (in GWhs)                                              2003         2002     Variance     % Change
     -------------------------------------------------------------------------------------------------------------------
     Nuclear Generation (1)                                               89,101       86,127        2,974        3.5%
     Purchases - non-trading portfolio (2)                                63,435       59,496        3,939        6.6%
     Fossil and Hydro Generation                                          18,041       10,112        7,929       78.4%
     -----------------------------------------------------------------------------------------------------
     Total Supply                                                        170,577      155,735       14,842        9.5%
     =====================================================================================================
<FN>
     (1) Excluding AmerGen.
     (2) Including PPAs with AmerGen.
</FN>
</TABLE>

              Trading volumes of 28,532 GWhs and 51,260 GWhs for the nine months
     ended  September 30, 2003 and 2002,  respectively,  are 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 nine
     months ended September 30, 2003 and 2002 were as follows:

<TABLE>
<CAPTION>
                                                                        Nine Months Ended September 30,
                                                                        -------------------------------
      ($/MWh)                                                                   2003               2002        % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                      <C>              <C>                     <C>
     Average Revenue
         Energy Delivery and Exelon Energy Company                       $     35.45      $      34.86            1.7%
         Market Sales                                                          37.11             31.55           17.6%
         Total - excluding the trading portfolio                               36.24             33.56            8.0%

     Average Supply Cost (1) - excluding the trading portfolio           $     23.67      $      21.04           12.5%

     Average Margin - excluding the trading portfolio                    $     12.57       $     12.52            0.4%
     -----------------------------------------------------------------------------------------------------------------
<FN>
     (1)  Average supply cost includes purchased power and fuel costs.
</FN>
</TABLE>


<TABLE>
<CAPTION>
                                                                                        Nine Months Ended September 30,
                                                                                        -------------------------------
                                                                                                   2003            2002
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                                          <C>             <C>
     Nuclear fleet capacity factor (1)                                                             94.5%           92.1%
     Nuclear fleet production cost per MWh (1)                                               $    12.16       $   13.05
     Average purchased power cost for wholesale operations per MWh (2)                       $    45.42       $   43.60
     -------------------------------------------------------------------------------------------------------------------
<FN>
     (1)  Including AmerGen and excluding Salem, which is operated by PSE&G.
     (2)  Including PPAs with AmerGen.
</FN>
</TABLE>

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

                                       96
<PAGE>

              Generation's average revenue per MWh was affected by:
     o    higher market prices as a result of increased fuel prices and
     o    increased  weighted  average on and off-peak prices per MWh for supply
          agreements with ComEd and PECO.

              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 6,565 GWhs,
     o    increased quantity of purchased power at higher prices, and
     o    a new PPA with AmerGen entered into during the second quarter of 2003,
          resulting in 2,481 GWhs purchased from Oyster Creek in 2003.

              Higher nuclear capacity factors and decreased  nuclear  production
     costs  are  primarily  due  to 66  fewer  planned  refueling  outage  days,
     resulting  in a $44 million  decrease in outage  costs,  in the nine months
     ended  September 30, 2003 as compared to the same period in 2002.  The nine
     months ended  September 30, 2003 and 2002 included 20 unplanned  outages in
     each year.

              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 and reduced  generation
     due to  maintenance  and  mid-cycle  outages.  For  example,  in the second
     quarter of 2003,  the Quad Cities Unit 1 required a significant  repair and
     did not operate above 85% capacity  factor until a root cause  analysis was
     completed.  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
     completed  the  analysis  and  returned  the unit to its  normal  operating
     capacity in August 2003.

     Results of Operations - Enterprises

<TABLE>
<CAPTION>
                                                             Nine Months Ended September 30,
                                                             -------------------------------
                                                                            2003         2002     Variance     % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                      <C>          <C>          <C>            <C>
     Operating revenues                                                  $ 1,459      $ 1,475      $   (16)       (1.1%)
     Operating loss                                                          (60)         (35)         (25)        71.4%
     Income (loss) before income taxes and cumulative effect
       of changes in accounting principles                                   (99)         115         (214)     (186.1%)
     Income (loss) before cumulative effect of changes in
       accounting principles                                                 (62)          69         (131)    (189.9%)
     Net loss                                                                (63)        (174)         111      (63.8%)
     -------------------------------------------------------------------------------------------------------------------
</TABLE>


                                       97
<PAGE>

              The  changes in  Enterprises'  operating  loss for the nine months
     ended September 30, 2003 compared to the same period in 2002,  included the
     following:
     o    an impairment charge of $48 million,  before income taxes and minority
          interest,  related to the goodwill of InfraSource  recorded during the
          second  quarter of 2003,  partially  offset by a gain of $44  million,
          before income taxes, related to the sale of the electric  construction
          and services, underground and telecom business of InfraSource recorded
          during the third quarter of 2003,
     o    lower  operating  income  at  InfraSource  of  $25  million  primarily
          resulting  from a decrease in the  electric  business of $37  million,
          partially  offset by lower  depreciation of $10 million as a result of
          the classification of InfraSource's  property,  plant and equipment as
          held for sale during the second quarter of 2003,
     o    lower operating income at Exelon Services of $3 million as a result of
          reduced construction projects,
     o    higher  operating  income  at  Exelon  Energy  Company  of $3  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 costs of $2
          million.  These costs were partially  offset by lower gross margins of
          $13  million  in 2003.  The  lower  gross  margins  resulted  from the
          reversal of  mark-to-market  adjustments of $13 million and additional
          gas supply  costs and  business  wind-down  costs of $12  million  for
          Northeast operations,  partially offset by higher gross margins of $10
          million in the Midwest attributable to increased unit margins,  higher
          volumes,  and higher  natural gas prices,  and a $2 million  favorable
          variance related to the wind-down of a contract, and
     o    higher operating income at Exelon Thermal of $4 million resulting from
          lower production costs.

              The  changes in other  income and  deductions  for the nine months
     ended  September 30, 2003 compared to the same period in 2002,  include the
     following additional impacts:
     o    a gain of $198 million,  before income taxes, in the second quarter of
          2002 due to the sale of the investment in AT&T Wireless, 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 37.4% for the nine months ended
     September  30,  2003,  compared to 40.0% 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  and sale of the  InfraSource
     businesses.

              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



                                       98
<PAGE>

     taxes. See Note 2 of the Condensed Combined Notes to Consolidated Financial
     Statements for further discussion of these effects.

              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.

     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.

              Exelon is in the process of  implementing  its new business  model
     referred to as The Exelon Way. This business  model is focused on improving
     operating  cash flows  while  meeting  service  and  financial  commitments
     through  integration of operations and consolidation of support  functions.
     Exelon has  targeted  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  has
     identified  1,042  positions


                                       99
<PAGE>

    for  elimination by the end of 2004 and anticipates  identifying  additional
    positions for  elimination  in 2005 and 2006.  Exelon  recorded a charge for
    cash  severance of $87 million  during the third quarter 2003,  which Exelon
    anticipates will be paid by December 31, 2004. Exelon anticipates  incurring
    further costs  associated  with The Exelon Way upon  identifying  additional
    positions  to be  eliminated.  These costs will be recorded in the period in
    which the costs can be reasonably estimated.

              On September 26, 2003 Exelon  announced  that it was exploring the
     possibility of acquiring Illinois Power Company from Dynegy Corporation.


     Cash Flows from Operating Activities

              Cash  flows  provided  by  operations  for the nine  months  ended
     September  30, 2003 were $2.6 billion  compared to $2.7 billion in the nine
     months ended  September 30, 2002.  The decrease in cash flows was primarily
     attributable  to the $360 million  funding of pension  benefit  obligations
     partially  offset by a $162 million  increase in cash flows  generated from
     working  capital.  Energy  Delivery'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.  Energy  Delivery's  future cash
     flows will depend upon the ability to achieve  cost  savings in  operations
     and  the  impact  of the  economy,  weather,  customer  choice  and  future
     regulatory  proceedings  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 nine months ended
     September 30, 2003 were $1.3 billion, compared to $1.9 billion for the nine
     months ended  September  30, 2002.  The decrease in cash used for investing
     activities  during the current year is primarily  attributable to the plant
     acquisition  costs of $443 million  during the nine months ended  September
     30, 2002, the reduction of capital expenditures of $33 million, the receipt
     of liquated  damages  from  Raytheon of $92 million  during the nine months
     ended  September  30, 2003 and an increase in cash  proceeds  from  related
     parties  of $77  million,  partially  offset by  increased  investments  in
     nuclear  decommissioning  trust fund assets of $17  million.  Additionally,
     cash flows from investing activities in 2002 include the cash proceeds from
     the sale of AT&T of $285  million,  while  cash  proceeds  from the sale of
     InfraSource during the current year were $175 million.

                                      100
<PAGE>

                Capital  expenditures  by  business  segment for the nine months
     ended September 30, 2003 and 2002 were as follows:

<TABLE>
<CAPTION>
                                                                                       Nine Months Ended September 30,
                                                                                       --------------------------------
                                                                                                 2003              2002
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                                          <C>              <C>
     Energy Delivery                                                                         $    728         $     729
     Generation                                                                                   641               715
     Enterprises                                                                                   19                34
     Corporate and other                                                                           21                56
     -------------------------------------------------------------------------------------------------------------------
     Total capital expenditures (net of liquidated damages received)                         $  1,409         $   1,534
     ===================================================================================================================
</TABLE>

              Energy Delivery's capital expenditures for 2003 reflect continuing
     efforts  to  further  improve  the  reliability  of  its  transmission  and
     distribution  systems and capital  additions  to support new  business  and
     customer  growth.   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 EBG generating  facilities with capacity of 2,421 MWs
     of energy,  additions  to and  upgrades of existing  facilities  (including
     nuclear refueling outages),  and nuclear fuel. During the nine months ended
     September  30, 2003,  EBG received $92 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.  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 $1.1 billion for the
     nine months ended  September 30, 2003 compared to $828 million for the same
     period in 2002.  The increased use of cash over the prior year is primarily
     attributable to the $210 million payment of the acquisition note payable to
     Sithe in June 2003 and increased interest rate swap settlement  payments of
     $35 million over the same period in 2002,  partially  offset by an increase
     in cash  proceeds  from the exercise of stock  options of $75 million and a
     net  increase in cash  proceeds  from the  issuance  of debt and  preferred
     securities  of $14 million over the same period in 2002. See Note 12 of the
     Condensed Combined Notes to Consolidated  Financial  Statements for further
     discussion of Exelon's debt and preferred  securities  financing activities
     in 2003.

              Dividends paid on common stock increased from $420 million for the
     nine months  ended  September  30, 2002 to $461 million for the nine months
     ended  September 30, 2003. On July 29, 2003,  the Exelon Board of Directors
     declared  a  dividend  of  $0.50  per  share  on  Exelon's   common  stock,
     representing an increase of $0.16 per share annually or approximately 8.7%.
     Payment of future  dividends is subject to approval and  declaration by the
     Board.


                                      101
<PAGE>

     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  and  PECO.  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. At September 30, 2003,  sublimits under
     the credit  facility were $1.0  billion,  $100 million and $400 million for
     Exelon Corporate,  ComEd and PECO, respectively.  Generation did not have a
     sublimit under the facility at September 30, 2003.  The credit  facility is
     used  principally  to  support  the  commercial  paper  programs  of Exelon
     Corporate,  ComEd and PECO.  At September 30, 2003,  Exelon's  Consolidated
     Balance Sheet reflected $82 million of commercial  paper  outstanding.  For
     the nine months ended  September  30, 2003,  the average  interest  rate on
     notes payable was approximately 1.28%.

              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 September 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 September 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, PECO,  Generation and Exelon Business Services
     Company (BSC) may  participate  in the money pool as lenders and borrowers,
     and  Exelon  Corporate  may  participate  as  a  lender.  Funding  of,  and
     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 nine
     months ended September 30, 2003, ComEd had various investments in the money
     pool,  and  Generation  had various loans from the money pool.  The maximum
     amount of ComEd's  investments and  Generation's  loans  outstanding at any
     time  during  2003  was  $344  million.  As  of  September  30,  2003,  the
     outstanding  ComEd investment and Generation loan balance was $147 million.
     During  the  nine  months  ended  September  30,  2003,  PECO  had  various
     investments  in the money pool,  and BSC had  various  loans from the money
     pool. The maximum amount of PECO's  investments and

                                      102
<PAGE>

     BSC's loans  outstanding  at any time during  2003 was $59  million.  As of
     September 30, 2003,  there were no outstanding PECO investments or BSC loan
     balances.

              EBG has  approximately  $1.1 billion of debt  outstanding  under a
    $1.25 billion credit  facility (EBG Facility) at September 30, 2003. The EBG
    Facility was entered into primarily to finance the  construction of Mystic 8
    and 9 and Fore River.  The EBG  Facility  required  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 were  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.
    Project Completion was not achieved by July 12, 2003,  resulting in an event
    of default  under the EBG  Facility.  The EBG  Facility is  non-recourse  to
    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. Mystic 8 and 9 and Fore River are in commercial operation,
    although they have not yet achieved Project Completion.

              As a result of Exelon's continuing  evaluation of the projects and
     discussions  with the  lenders,  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 its 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.

              The debt outstanding under the EBG Facility of approximately  $1.1
     billion at September 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  of $210  million  relating  to the  $536  million  note,  which  was
     established in connection with the acquisition of Exelon New England.

              On  September  29,  2003,  Generation  replaced  the $550  million
     facility with a new $850 million  revolving credit  facility.  The existing
     $210 million of borrowings under the original  facility remain  outstanding
     under the new credit facility.  The note with Sithe was restructured in the
     third  quarter to provide for the  remaining  balance of $326 million to be
     paid in two installments. Generation will be required to repay $236 million
     of the  principal  on the earlier of December 1, 2003 or change of control,
     and the remaining  principal  balance on the earlier of December 1, 2004 or
     change of control.

              Generation's $850 million facility is also expected to provide the
     initial  funding of the  acquisition  of British  Energy's  50% interest in
     AmerGen.

                                      103
<PAGE>

              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.

              As part of the normal  course of business,  Exelon and  Generation
     routinely  enter into  physical or  financially  settled  contracts for the
     purchase  and sale of capacity,  energy,  fuels and  emissions  allowances.
     These  contracts  either  contain  express  provisions or otherwise  permit
     Exelon,  Generation and its  counterparties to demand adequate assurance of
     future  performance  when  there are  reasonable  grounds  for doing so. In
     accordance  with the contracts and  applicable  contracts law, if Exelon or
     Generation  is downgraded  by a credit  rating  agency,  especially if such
     downgrade  is to a level below  investment  grade,  it is  possible  that a
     counterparty  could  attempt  to rely on such a  downgrade  as a basis  for
     making a demand for adequate assurance of future performance.  Depending on
     Exelon or Generation's  net position with a counterparty,  the demand could
     be for the posting of  collateral.  In the absence of  expressly  agreed to
     provisions  that  specify  the  collateral  that  must  be  provided,   the
     obligation  to supply the  collateral  requested  will be a function of the
     facts and circumstances of Exelon or Generation's  situation at the time of
     the demand. If Exelon or Generation can reasonably claim that it is willing
     and  financially  able to perform  its  obligations,  it may be possible to
     successfully  argue  that no  collateral  should  be posted or that only an
     amount  equal  to  two  or  three  months  of  future  payments  should  be
     sufficient.

              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 September 30, 2003,  there was $2.7 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 September  30, 2003,  Exelon had
     provided $1.85 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 September 30,
     2002 of not less than 30%. At September 30, 2003, Exelon and ComEd's common
     equity ratios were 35% and 47%, 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.  Furthermore,  a
     significant  loss recorded at ComEd


                                      104
<PAGE>

     may limit the dividends that ComEd can distribute to Exelon.  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  September  30,  2003,  Exelon had  retained  earnings of $2.2  billion,
     including  ComEd's  retained  earnings  of $836  million,  PECO's  retained
     earnings of $517 million and  Generation's  undistributed  earnings of $577
     million.  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 September 30, 2003, Exelon had
     invested $2.8 billion in EWGs, leaving $1.2 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  September  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.

               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

                                      105
<PAGE>

          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 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 net one-time charge for these items was $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) and have made  refundable  prepayments  of $11
          million and $1 million,  respectively,  for potential fees  associated
          with these  agreements.  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,  ultimate  net cash
          flows to ComEd and PECO  related to these  agreements  will  either be
          positive or neutral  depending  upon the  outcome of the refund  claim
          with the IRS. 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 12 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  through  April 9,  2009.  See  Note 9 of the  Condensed
          Combined Notes to Consolidated Financial Statements for the commercial
          commitments table  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
          purchase of the 35.2%  interest in Sithe owned by Apollo  Energy,  LLC
          and the 14.9% interest owned by subsidiaries of Marubeni  Corporation.
          The total  purchase price under the call was based on the terms of the
          existing  Put and Call  Agreement  (PCA) among the parties and is $621
          million.   The  transfer  of  ownership  requires  various  regulatory
          approvals,  including the Federal Energy Regulatory Commission (FERC),
          the state  environmental  agency in New Jersey,  and expiration of the
          Hart Scott Rodino


                                      106
<PAGE>

          waiting  period.  Early  termination  of the Hart Scott Rodino waiting
          period was granted effective August 22, 2003.

               Under the terms of the PCA,  the  purchase  price  must be funded
          within  six  months of the call  notice  being  issued.  Additionally,
          because the Federal Power Act restricts Generation's ownership of more
          than 50% of qualifying facilities,  the qualifying facilities owned by
          Sithe must be sold or  restructured  before  closing to preserve their
          status as qualifying facilities. See below for information regarding a
          separate  agreement  reached  by Sithe  to sell  six  U.S.  generating
          facilities,  each a qualifying facility, and an entity holding Sithe's
          Canadian  assets.  At the closing,  Sithe is expected to distribute in
          excess of $600 million of available cash to Generation.

               On August  13,  2003,  Generation  announced  an  agreement  with
          entities controlled by Reservoir Capital Group (Reservoir),  a private
          investment firm, to sell 50% of Sithe in exchange for $75.8 million in
          cash. The sale will occur after Generation's purchase of the remaining
          50.1% interest in Sithe. The sale requires FERC approval, a Hart Scott
          Rodino filing and a filing with the state regulatory commission in New
          York. Both of these filings have been made.  Early  termination of the
          Hart Scott Rodino waiting  period was granted  September 30, 2003. The
          sale is expected to close in the fourth quarter of 2003.

               Both  Generation and  Reservoir's  50% interests in Sithe will be
          subject  to put and call  options  that could  result in either  party
          owning 100% of Sithe.  While  Generation's  intent is to fully  divest
          Sithe by the end of 2004,  the timing of the put and call options vary
          by acquirer and can extend  through March 2006. The pricing of the put
          and  call  options  is  dependent  on  numerous  factors  such  as the
          acquirer, date of acquisition and assets owned by Sithe at the time of
          exercise.

               In a separate  transaction,  Sithe has entered  into an agreement
          with   Reservoir  to  sell  entities   holding  six  U.S.   generating
          facilities,  each a  qualifying  facility  under  the  Public  Utility
          Regulatory Policies Act, and an entity holding Sithe's Canadian assets
          in exchange for $46.2 million ($26.2 million in cash and a $20 million
          two-year  note).  The sale  requires  approvals  from Sithe's board of
          directors and  shareholders  and regulatory  filings in New Jersey and
          Canada.  Both of  these  filings  have  been  made.  The  sale is also
          expected  to close in the  fourth  quarter  of 2003.  This sale is not
          contingent on the sale of Exelon's 50% interest in Sithe to Reservoir.

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

     o    On  August  14,  2003,  Generation  received  a  letter  from  the DOE
          demanding repayment of $40 million of previously received credits from
          the Nuclear  Waste  Fund.  The letter also  demanded  $1.5  million of
          accrued  interest  expense.  Although a new  settlement  would  offset
          Generation's  payments,  Generation  nonetheless  has reserved its 50%
          ownership  share of these  amounts.  Because  Generation  expenses the
          casks and  capitalizes  the  permanent  components  of its spent  fuel
          storage facilities,  these reserves increased  Generation's  operating
          and maintenance expense approximately $11 million and its capital base

                                      107
<PAGE>

          approximately  $9  million  during  the  third  quarter  of 2003.  The
          remainder of the recorded obligation to the DOE will be recovered from
          the co-owner of the facility. See Note 9 - Nuclear Decommissioning and
          Spent  Nuclear  Fuel  Storage  in  Generation's  2002  Form  10-K  for
          additional information regarding this matter.

     o    Under the  Price-Anderson  Act, all nuclear  reactor  licensees can be
          assessed a maximum charge per reactor per incident.  Effective  August
          20, 2003, the maximum assessment for all nuclear operators per reactor
          per incident (including a 5% surcharge)  increased from $89 million to
          $101 million. The maximum payable per reactor per incident per year of
          $10 million is unchanged.  The change in the maximum assessment is the
          result of an inflation adjustment, required by the Price-Anderson Act.
          Based on the  increase of the  maximum  assessment,  Exelon's  nuclear
          insurance guarantees increased from $1,380 million to $1,559 million.

     o    On October 10, 2003,  Exelon executed an agreement to purchase British
          Energy's 50% interest in AmerGen for $276.5  million.  The transaction
          is expected  to close in the first half of 2004.  The  purchase  price
          matched the offer by FPL Energy, which announced on September 11, 2003
          that it intended to buy British  Energy's share of AmerGen.  Under the
          AmerGen limited liability  company operating  agreement between Exelon
          and British  Energy,  either can exercise a right of first  refusal by
          matching  any bona  fide  third-party  offer  agreed  to by the  other
          member.  See Note 4 of the Condensed  Combined  Notes to  Consolidated
          Financial Statements for additional information regarding AmerGen.


                                      108
<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  September  30, 2003  Compared to Three  Months  Ended
     September 30, 2002

     Significant Operating Trends - ComEd
<TABLE>
<CAPTION>
                                                             Three Months Ended September 30,
                                                             --------------------------------
                                                                            2003         2002     Variance     % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                    <C>           <C>           <C>          <C>
     OPERATING REVENUES                                                $   1,737     $  1,938      $  (201)     (10.4%)

     OPERATING EXPENSES
         Purchased power                                                     891          975          (84)      (8.6%)
         Operating and maintenance                                           299          267           32       12.0%
         Depreciation and amortization                                        97          129          (32)     (24.8%)
         Taxes other than income                                              87           77           10       13.0%
     -----------------------------------------------------------------------------------------------------
              Total operating expenses                                     1,374        1,448          (74)      (5.1%)
     -----------------------------------------------------------------------------------------------------

     OPERATING INCOME                                                        363          490         (127)     (25.9%)
     -----------------------------------------------------------------------------------------------------

     OTHER INCOME AND DEDUCTIONS
         Interest expense                                                   (107)        (122)          15      (12.3%)
         Distributions on mandatorily redeemable preferred securities         (6)          (7)           1      (14.3%)
         Other, net                                                           15           --           15     n.m.
     -----------------------------------------------------------------------------------------------------
              Total other income and deductions                              (98)        (129)          31      (24.0%)
     -----------------------------------------------------------------------------------------------------

     INCOME BEFORE INCOME TAXES                                              265          361          (96)     (26.6%)

     INCOME TAXES                                                            102          146          (44)     (30.1%)
     -----------------------------------------------------------------------------------------------------
     NET INCOME                                                        $     163     $    215      $   (52)     (24.2%)
     =====================================================================================================
<FN>
     n.m. - not meaningful
</FN>
</TABLE>

     Net Income
              Net income  decreased  $52  million,  or 24%, for the three months
     ended September 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 charges associated with
     The Exelon Way severance partially offset by lower amortization expense and
     lower interest expense.

                                      109
<PAGE>

     Operating Revenues
         ComEd's electric sales statistics were as follows:

<TABLE>
<CAPTION>
                                                    Three Months Ended September 30,
                                                    --------------------------------
     Retail Deliveries - (in GWhs)                            2003              2002         Variance          % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                          <C>               <C>               <C>           <C>
     Bundled Deliveries (1)
     Residential                                             8,197             9,121             (924)         (10.1%)
     Small Commercial & Industrial                           5,749             6,029             (280)          (4.6%)
     Large Commercial & Industrial                           1,539             2,073             (534)         (25.8%)
     Public Authorities & Electric Railroads                 1,269             1,612             (343)         (21.3%)
     -------------------------------------------------------------------------------------------------
                                                            16,754            18,835           (2,081)         (11.0%)
     -------------------------------------------------------------------------------------------------
     Unbundled Deliveries (2)
     ARES
     ----
     Small Commercial & Industrial                           1,721             1,640               81            4.9%
     Large Commercial & Industrial                           2,934             2,192              742           33.9%
     Public Authorities & Electric Railroads                   426               299              127           42.5%
     -------------------------------------------------------------------------------------------------
                                                             5,081             4,131              950           23.0%
     -------------------------------------------------------------------------------------------------
     PPO
     ---
     Small Commercial & Industrial                             884               782              102           13.0%
     Large Commercial & Industrial                             896             1,249             (353)         (28.3%)
     Public Authorities & Electric Railroads                   428               345               83           24.1%
     -------------------------------------------------------------------------------------------------
                                                             2,208             2,376             (168)          (7.1%)
     -------------------------------------------------------------------------------------------------
         Total Unbundled Deliveries                          7,289             6,507              782           12.0%
     -------------------------------------------------------------------------------------------------
     Total Retail Deliveries                                24,043            25,342           (1,299)          (5.1%)
     =================================================================================================
<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 ARES or the PPO.
</FN>
</TABLE>


                                      110
<PAGE>

<TABLE>
<CAPTION>
                                                    Three Months Ended September 30,
                                                    --------------------------------
     Electric Revenue                                         2003              2002         Variance          % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                     <C>               <C>                 <C>               <C>
     Bundled Revenues (1)
     Residential                                        $      760        $      840          $   (80)          (9.5%)
     Small Commercial & Industrial                             487               506              (19)          (3.8%)
     Large Commercial & Industrial                              82               106              (24)         (22.6%)
     Public Authorities & Electric Railroads                    82               104              (22)         (21.2%)
     -------------------------------------------------------------------------------------------------
                                                             1,411             1,556             (145)          (9.3%)
     -------------------------------------------------------------------------------------------------
     Unbundled Revenues (2)
     ARES
     ----
     Small Commercial & Industrial                              34                51              (17)         (33.3%)
     Large Commercial & Industrial                              41                60              (19)         (31.7%)
     Public Authorities & Electric Railroads                     8                10               (2)         (20.0%)
     -------------------------------------------------------------------------------------------------
                                                                83               121              (38)         (31.4%)
     -------------------------------------------------------------------------------------------------
     PPO
     ---
     Small Commercial & Industrial                              65                57                8           14.0%
     Large Commercial & Industrial                              56                74              (18)         (24.3%)
     Public Authorities & Electric Railroads                    26                19                7           36.8%
     -------------------------------------------------------------------------------------------------
                                                               147               150               (3)          (2.0%)
     -------------------------------------------------------------------------------------------------
     Total Unbundled Revenues                                  230               271              (41)         (15.1%)
     -------------------------------------------------------------------------------------------------
     Total Electric Retail Revenues                          1,641             1,827             (186)         (10.2%)
     Wholesale and Miscellaneous Revenue (3)                    96               111              (15)         (13.5%)
     -------------------------------------------------------------------------------------------------
     Total Electric Revenue                               $  1,737         $   1,938          $  (201)         (10.4%)
     =================================================================================================
<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 three months ended
     September  30,  2003,  as  compared  to  the  same  period  in  2002,   are
     attributable to the following:

<TABLE>
<CAPTION>
                                                                                                               Variance
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                                                          <C>
     Weather                                                                                                 $     (143)
     Rate changes                                                                                                   (52)
     Customer choice                                                                                                (36)
     Volume                                                                                                          40
     Other effects                                                                                                    5
     -------------------------------------------------------------------------------------------------------------------
     Electric retail revenue                                                                                 $     (186)
     ===================================================================================================================
</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 September 30, 2003 was unfavorable  compared to the
          same  period  in 2002 as a result of cooler  summer  weather  in 2003.
          Cooling degree-days  decreased 25% in the three months



                                      111
<PAGE>

          ended September 30, 2003 compared to the same period in 2002, and were
          3% lower than normal.
     o    Rate  Changes.  The decrease in collection of CTCs in 2003 by ComEd of
          $81 million due to a decrease in the CTC rates due to higher wholesale
          market prices of  electricity,  net of increased  mitigation  factors.
          This was partially  offset by increased  wholesale market prices which
          increased  energy  revenue  received under ComEd's PPO by $29 million.
          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 5 of the Condensed  Combined Notes
          to Consolidated Financial Statements, decreases the collection of CTCs
          as compared to the respective period in 2002.
     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  September  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  September  30,  2003,  the  energy
          provided  by  alternative  suppliers  was 5,081  GWhs,  or  21.1%,  as
          compared to 4,131 GWhs, or 16.3%, for the three months ended September
          30, 2002.
               The decrease in revenues reflects  customers in Illinois electing
          to purchase  energy from an ARES or the PPO. As of September 30, 2003,
          the number of retail  customers  that had elected to  purchase  energy
          from an ARES or the ComEd PPO was  approximately  20,000,  or 0.6%, as
          compared to 22,700,  or 0.6%, as of September 30, 2002. MWhs delivered
          to such  customers  increased from  approximately  6.5 million for the
          three  months  ended  September  30, 2002 to 7.3 million for the three
          months ended September 30, 2003, or from 26% to 30% of total quarterly
          retail deliveries.
     o    Volume.  Revenues from higher delivery  volume,  exclusive of weather,
          increased  due  to  an  increased   usage  per   customer,   primarily
          residential and small commercial and industrial.

              Wholesale  and  miscellaneous  revenue for the three  months ended
     September  30, 2003  compared to the three months ended  September 30, 2002
     decreased $15 million primarily due to a 2002 reimbursement from Generation
     of $12 million for third-party energy reconciliations.

     Purchased Power
              Purchased  power  expense  decreased  $84 million,  or 9%, for the
     three months ended  September  30,  2003.  The decrease in purchased  power
     expense  was  primarily  attributable  to a $75  million  decrease  due  to
     unfavorable  weather  conditions,  a $42  million  decrease  as a result of
     customers  choosing to purchase energy from an ARES, a $20 million decrease
     due to additional  energy billed in 2002 under the PPA with Generation as a
     result of  third-party  energy  reconciliations  discussed in the operating
     revenue section above,  partially  offset by an increase of $22 million due
     to higher volume,  $21 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. The $16 million  increase in purchased  power  expense  related to
     SFAS  No.  143 had no  impact  on net  income  as it was  offset  by  lower
     regulatory asset amortization in depreciation and amortization expense.


                                      112
<PAGE>

     Operating and Maintenance
              O&M expense  increased  $32 million,  or 12%, for the three months
     ended  September  30,  2003.  The  increase in O&M  expense  was  primarily
     attributable  to $60  million  of The  Exelon  Way  severance  and  related
     postretirement  health  and  welfare  benefits  accruals  and  pension  and
     postretirement   curtailment   costs   and  $12   million   of   additional
     storm-related  costs,  partially  offset by a 2002 $17 million  increase in
     manufactured gas plant (MGP)  investigation and remediation reserve charges
     net of 2003 increases, a decrease in payroll expenses of $15 million due to
     fewer employees, and a decrease of $6 million in bad debt expense.

     Depreciation and Amortization
              Depreciation and amortization  expense  decreased $32 million,  or
     25%, for the three months ended September 30, 2003 as follows:

<TABLE>
<CAPTION>
                                                    Three Months Ended September 30,
                                                    --------------------------------
                                                              2003              2002         Variance          % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                       <C>              <C>               <C>                   <C>
     Depreciation expense                                 $     77         $      75         $      2              2.7%
     Recoverable transition costs amortization                  12                33              (21)          (63.6%)
     Other amortization expense                                  8                21              (13)          (61.9%)
     -------------------------------------------------------------------------------------------------
     Total depreciation and amortization                  $     97         $     129         $    (32)          (24.8%)
     =================================================================================================
</TABLE>

              The increase in  depreciation  expense is primarily  due to higher
     property, plant and equipment balances.

              Recoverable  transition costs amortization  decreased in the three
     months ended  September 30, 2003  compared to the same period in 2002.  The
     decrease is a result of additional  amortization in 2002.  ComEd expects to
     fully recover its recoverable  transition costs regulatory asset balance of
     $141  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 had no
     impact on net income as it was  offset by  increased  purchased  power from
     Generation.

     Taxes Other Than Income
              Taxes other than income  increased  by $10  million,  or 13%, as a
     result of a $5  million  real  estate  tax refund in 2002 and $8 million in
     2003 for use tax payments for periods prior to the Merger.

     Interest Charges
              Interest charges consist of interest expense and  distributions on
     mandatorily redeemable preferred securities. Interest charges decreased $16
     million,  or 12%, for the three months ended September 30, 2003 as a result
     of scheduled  principal  payments and  refinancing  existing  debt at lower
     interest rates.

                                      113
<PAGE>

     Other, Net
              Other,  net  increased  by $15 million for the three  months ended
     September 30, 2003 as compared to the same period in 2002.  In 2002,  ComEd
     recorded a $12 million reserve  accrual for a potential plant  disallowance
     from an audit performed in conjunction with ComEd's delivery  services rate
     case.  This $12 million was reversed in March 2003 as a result of the March
     3, 2003  agreement  - as more fully  described  in Note 5 to the  Condensed
     Combined Notes to Consolidated Financial Statements.

     Income Taxes
              The effective income tax rate was 38.5% for the three months ended
     September 30, 2003,  compared to 40.4% for the three months ended September
     30, 2002.


     Nine  Months  Ended  September  30,  2003  Compared  to Nine  Months  Ended
     September 30, 2002

     Significant Operating Trends - ComEd
<TABLE>
<CAPTION>
                                                              Nine Months Ended September 30,
                                                              -------------------------------
                                                                            2003         2002     Variance     % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                    <C>           <C>           <C>           <C>
     OPERATING REVENUES                                                $   4,522     $  4,734      $  (212)      (4.5%)

     OPERATING EXPENSES
         Purchased power                                                   2,001        2,066          (65)      (3.1%)
         Operating and maintenance                                           781          724           57        7.9%
         Depreciation and amortization                                       287          397         (110)     (27.7%)
         Taxes other than income                                             235          223           12        5.4%
     -----------------------------------------------------------------------------------------------------
              Total operating expenses                                     3,304        3,410         (106)      (3.1%)
     -----------------------------------------------------------------------------------------------------

     OPERATING INCOME                                                      1,218        1,324         (106)      (8.0%)
     -----------------------------------------------------------------------------------------------------

     OTHER INCOME AND DEDUCTIONS
         Interest expense                                                   (322)        (374)          52      (13.9%)
         Distributions on mandatorily redeemable preferred securities        (20)         (22)           2       (9.1%)
         Other, net                                                           48           29           19       65.5%
     -----------------------------------------------------------------------------------------------------
              Total other income and deductions                             (294)        (367)          73      (19.9%)
     -----------------------------------------------------------------------------------------------------

     INCOME BEFORE INCOME TAXES AND CUMULATIVE
       EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE                            924          957          (33)      (3.4%)
     INCOME TAXES                                                            365          381          (16)      (4.2%)
     -----------------------------------------------------------------------------------------------------

     NET INCOME BEFORE CUMULATIVE EFFECT OF
       A CHANGE IN ACCOUNTING  PRINCIPLE                                     559          576          (17)      (3.0%)

     CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING
       PRINCIPLE                                                               5           --            5     n.m.
     -----------------------------------------------------------------------------------------------------
     NET INCOME                                                        $     564     $    576      $   (12)      (2.1%)
     =====================================================================================================
<FN>
     n.m. - not meaningful
</FN>
</TABLE>

     Net Income
              Net income decreased $12 million, or 2%, for the nine months ended
     September  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



                                      114
<PAGE>

     charges associated with The Exelon Way severance  partially offset by lower
     depreciation and amortization expense and lower interest expense.

     Operating Revenues
              ComEd's electric sales statistics were as follows:

<TABLE>
<CAPTION>
                                                     Nine Months Ended September 30,
                                                     -------------------------------
     Retail Deliveries - (in GWhs)                            2003              2002         Variance          % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                         <C>               <C>              <C>              <C>
     Bundled Deliveries (1)
     Residential                                            20,246            21,392           (1,146)          (5.4%)
     Small Commercial & Industrial                          16,490            17,078             (588)          (3.4%)
     Large Commercial & Industrial                           4,706             6,151           (1,445)         (23.5%)
     Public Authorities & Electric Railroads                 4,018             5,097           (1,079)         (21.2%)
     -------------------------------------------------------------------------------------------------
                                                            45,460            49,718           (4,258)          (8.6%)
     -------------------------------------------------------------------------------------------------
     Unbundled Deliveries (2)
     ARES
     ----
     Small Commercial & Industrial                           4,327             3,822              505           13.2%
     Large Commercial & Industrial                           6,894             5,200            1,694           32.6%
     Public Authorities & Electric Railroads                   954               618              336           54.4%
     -------------------------------------------------------------------------------------------------
                                                            12,175             9,640            2,535           26.3%
     -------------------------------------------------------------------------------------------------
     PPO
     ---
     Small Commercial & Industrial                           2,546             2,384              162            6.8%
     Large Commercial & Industrial                           3,646             3,952             (306)          (7.7%)
     Public Authorities & Electric Railroads                 1,497               861              636           73.9%
     -------------------------------------------------------------------------------------------------
                                                             7,689             7,197              492            6.8%
     -------------------------------------------------------------------------------------------------
         Total Unbundled Deliveries                         19,864            16,837            3,027           18.0%
     -------------------------------------------------------------------------------------------------
     Total Retail Deliveries                                65,324            66,555           (1,231)          (1.8%)
     =================================================================================================
<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>

                                      115
<PAGE>


<TABLE>
<CAPTION>
                                                     Nine Months Ended September 30,
                                                     -------------------------------
     Electric Revenue                                         2003              2002         Variance          % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                     <C>               <C>                 <C>               <C>
     Bundled Revenues (1)
     Residential                                        $    1,778        $    1,881          $  (103)          (5.5%)
     Small Commercial & Industrial                           1,289             1,343              (54)          (4.0%)
     Large Commercial & Industrial                             240               324              (84)         (25.9%)
     Public Authorities & Electric Railroads                   247               297              (50)         (16.8%)
     -------------------------------------------------------------------------------------------------
                                                             3,554             3,845             (291)          (7.6%)
     -------------------------------------------------------------------------------------------------
     Unbundled Revenues (2)
     ARES
     ----
     Small Commercial & Industrial                             106                94               12           12.8%
     Large Commercial & Industrial                             133               101               32           31.7%
     Public Authorities & Electric Railroads                    25                18                7           38.9%
     -------------------------------------------------------------------------------------------------
                                                               264               213               51           23.9%
     -------------------------------------------------------------------------------------------------
     PPO
     ---
     Small Commercial & Industrial                             174               155               19           12.3%
     Large Commercial & Industrial                             199               214              (15)          (7.0%)
     Public Authorities & Electric Railroads                    81                48               33           68.8%
     -------------------------------------------------------------------------------------------------
                                                               454               417               37            8.9%
     -------------------------------------------------------------------------------------------------
     Total Unbundled Revenues                                  718               630               88           14.0%
     -------------------------------------------------------------------------------------------------
     Total Electric Retail Revenues                          4,272             4,475             (203)          (4.5%)
     Wholesale and Miscellaneous Revenue (3)                   250               259               (9)          (3.5%)
     -------------------------------------------------------------------------------------------------
     Total Electric Revenue                               $  4,522         $   4,734          $  (212)          (4.5%)
     =================================================================================================
<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.
     (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 nine months ended
     September  30,  2003,  as  compared  to  the  same  period  in  2002,   are
     attributable to the following:

<TABLE>
<CAPTION>
                                                                                                               Variance
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                                                          <C>
     Weather                                                                                                 $     (197)
     Customer choice                                                                                               (113)
     Volume                                                                                                          72
     Rate changes                                                                                                    23
     Other effects                                                                                                   12
     -------------------------------------------------------------------------------------------------------------------
     Electric retail revenue                                                                                 $     (203)
     ===================================================================================================================
</TABLE>

     o    Weather.  The weather  impact for the nine months ended  September 30,
          2003 was  unfavorable  compared to the same period in 2002 as a result
          of cooler summer weather in 2003. Cooling degree-days decreased 36% in
          the nine months ended  September  30, 2003 compared to the same period
          in 2002 and were partially  offset by a 15% increase in heating degree
          days in the nine months ended  September 30, 2003 compared to the same
          period in 2002.

                                      116
<PAGE>

     o    Customer  Choice.  The  decrease in  revenues  reflects  customers  in
          Illinois electing to purchase energy from an ARES or the PPO.
               For the nine months ended September 30, 2003, the energy provided
          by  alternative  suppliers was 12,175 GWhs,  or 18.6%,  as compared to
          9,640 GWhs, or 14.5%, for the nine months ended September 30, 2002.
               As of September 30, 2003, the number of retail customers that had
          elected  to  purchase  energy  from  an  ARES  or the  ComEd  PPO  was
          approximately  20,000,  or 0.6%, as compared to 22,700, or 0.6%, as of
          September 30, 2002.  MWhs delivered to such  customers  increased from
          approximately  16.8  million for the nine months ended  September  30,
          2002 to 19.9 million for the nine months ended  September 30, 2003, or
          from 25% to 30% of total year-to-date retail deliveries.
     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  small   commercial  and
          industrial.
     o    Rate Changes.  The increase in revenues  attributable  to rate changes
          reflects the  collection  of  additional  CTCs in 2003 by ComEd of $65
          million due to an increase in sales to  customers  choosing an ARES or
          the ComEd PPO and an increase in CTC rates due to the lower  wholesale
          market  price of  electricity,  net of increased  mitigation  factors.
          Lower wholesale market prices decreased revenue received under ComEd's
          PPO by $42  million.  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 5
          of the Condensed Combined Notes to Consolidated  Financial Statements,
          decreases the collection of CTCs as compared to the respective  period
          in 2002.

              Wholesale  and  miscellaneous  revenue for the nine  months  ended
     September  30, 2003  compared to the nine months ended  September  30, 2002
     decreased $9 million primarily due to a 2002  reimbursement from Generation
     of $12 million for third-party energy reconciliations.

     Purchased Power
              Purchased power expense decreased $65 million, or 3%, for the nine
     months ended  September 30, 2003.  The decrease in purchased  power expense
     was primarily  attributable  to a $102 million  decrease due to unfavorable
     weather and a $91 million  decrease  as a result of  customers  choosing to
     purchase  energy from an ARES,  a $20 million  decrease  due to  additional
     energy  billed  in 2002  under  the PPA  with  Generation  as a  result  of
     third-party  energy  reconciliations  discussed  in the  operating  revenue
     section above, partially offset by an increase of $44 million due to higher
     volume,  an  increase  of $60  million  due to pricing  changes  related to
     ComEd's PPA with  Generation  and an increase of $47 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 $47 million
     increase in purchased  power expense  related to SFAS No. 143 had no impact
     on net income as it was offset by lower  regulatory  asset  amortization in
     depreciation and amortization expense.

     Operating and Maintenance
              O&M  expense  increased  $57  million,  or 8%, for the nine months
     ended  September  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 5 of the

                                      117
<PAGE>

     Condensed Combined Notes to Consolidated Financial Statements,  $60 million
     due to The Exelon  Way  severance  and  related  postretirement  health and
     welfare benefits accruals and pension and postretirement curtailment costs,
     $13 million of additional  storm-related  costs and $16 million increase in
     employee fringe benefits partially offset by $5 million of higher corporate
     allocations  in 2002 due to  executive  severance,  $12  million  lower MGP
     investigation and remediation reserve charges,  net of 2003 increases,  and
     $53 million decrease in payroll expenses due to fewer employees.

     Depreciation and Amortization
              Depreciation and amortization  expense decreased $110 million,  or
     28%, for the nine months ended September 30, 2003 as follows:

<TABLE>
<CAPTION>
                                                     Nine Months Ended September 30,
                                                     -------------------------------
                                                              2003              2002         Variance          % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                       <C>              <C>               <C>                <C>
     Depreciation expense                                 $    229         $     258         $    (29)          (11.2%)
     Recoverable transition costs amortization                  34                75              (41)          (54.7%)
     Other amortization expense                                 24                64              (40)          (62.5%)
     -------------------------------------------------------------------------------------------------
     Total depreciation and amortization                  $    287         $     397         $   (110)          (27.7%)
     =================================================================================================

</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 nine months ended
     September  30,  2003.  The  decrease in  depreciation  expense is partially
     offset by increased depreciation due to capital additions.

              Recoverable  transition costs  amortization  decreased in the nine
     months ended  September 30, 2003  compared to the same period in 2002.  The
     decrease is a result of additional  amortization in 2002.  ComEd expects to
     fully recover its recoverable  transition costs regulatory asset balance of
     $141  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 had no
     impact on net income as it was  offset by  increased  purchased  power from
     Generation.

     Taxes Other Than Income
              Taxes other than income  increased $12 million or 5%, for the nine
     months  ended  September  30, 2003  primarily  as a result of $5 million in
     Illinois  Public  Utility  Fund taxes that were not  charged in 2002,  a $5
     million  real  estate tax refund in 2002 and $8 million in 2003 for



                                      118
<PAGE>

     use tax payments for periods prior to the Merger,  partially offset by a $5
     million refund in 2003 of Illinois Electricity Distribution taxes.

     Interest Charges
              Interest charges consist of interest expense and  distributions on
     mandatorily redeemable preferred securities. Interest charges decreased $54
     million, or 14%, for the nine months ended September 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 nine months ended  September 30, 2003 as compared to the nine
     months ended  September 30, 2002 and the annual  retirement of $340 million
     in Transitional Trust Notes.

     Other, Net
              Other, net increased $19 million or 66%, for the nine months ended
     September 30, 2003 as compared to the same period in 2002.  In 2002,  ComEd
     recorded a $12 million reserve  accrual for a potential plant  disallowance
     from an audit performed in conjunction with ComEd's delivery  services rate
     case.  This $12 million was reversed in March 2003 as a result of the March
     3, 2003  agreement  - as more fully  described  in Note 5 to the  Condensed
     Combined Notes to Consolidated Financial Statements.

     Income Taxes
              The effective  income tax rate was 39.5% for the nine months ended
     September 30, 2003,  compared to 39.8% for the nine months ended  September
     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.  See Note 2 of the  Condensed  Combined
     Notes to Consolidated  Financial  Statements for further  discussion of the
     adoption of SFAS No. 143.

     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,
     participation in the intercompany money pool 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



                                      119
<PAGE>

     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.

              As  part  of the  implementation  of The  Exelon  Way,  ComEd  has
    identified 451 positions for  elimination by the end of 2004 and anticipates
    identifying  additional  positions for  elimination in 2005 and 2006.  ComEd
    recorded a charge for cash severance of $37 million during the third quarter
    2003,  which ComEd  anticipates  will be paid by December  31,  2004.  ComEd
    anticipates  incurring  further  costs  associated  with The Exelon Way upon
    identifying  additional  positions  to be  eliminated.  These  costs will be
    recorded in the period in which the costs can be reasonably estimated.

     Cash Flows from Operating Activities

              Cash flows  provided by operations  were $742 million for the nine
     months  ended  September  30, 2003  compared  to $1.5  billion for the nine
     months ended  September  30,  2002.  The decrease in cash flows in 2003 was
     primarily  attributable to a $504 million  decrease in working capital as a
     result of the  paydown of  payables  to  affiliates  and other  outstanding
     liabilities,  a  decrease  of $127  million  for  pension  and  non-pension
     postretirement   benefits  obligation,   a  decrease  in  depreciation  and
     amortization  of $110 million.  ComEd's  future cash flows will depend upon
     the ability to achieve  cost  savings in  operations  and the impact of the
     economy,  weather, customer choice and future regulatory proceedings 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 $450 million for the
     nine months ended  September 30, 2003 compared to $528 million for the nine
     months  ended  September  30,  2002.  The  decrease  in cash  flows used in
     investing  activities in 2003 was primarily  attributable to the receipt of
     $213 million from Unicom  Investments Inc. related to an intercompany  note
     payable   partially   offset  by  $147  million   invested  in  the  Exelon
     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.

                                      120
<PAGE>

     Cash Flows from Financing Activities

              Cash flows used in financing  activities were $186 million for the
     nine  months  ended  September  30,  2003 as compared to cash flows used in
     financing  of $970 million for the nine months  ended  September  30, 2002.
     Cash flows used in financing activities were primarily attributable to debt
     issuances  and  payments  of  dividends  to  Exelon,  partially  offset  by
     retirements and  redemptions.  The decrease in cash flows used in financing
     activities  is  primarily  attributable  to  increased  debt and  preferred
     securities  issuances of $926 million,  partially  offset by increased debt
     and preferred securities redemptions of $139 million and increased interest
     rate swap settlement payments of $35 million.  See Note 12 of the Condensed
     Combined Notes to Consolidated  Financial Statements for further discussion
     of ComEd's debt and preferred securities financing activities. ComEd paid a
     $305 million  dividend to Exelon during the nine months ended September 30,
     2003  compared  to a $353  million  dividend  for  the  nine  months  ended
     September 30, 2002.

     Credit Issues

              ComEd  meets  its  short-term  liquidity   requirements  primarily
     through the issuance of commercial paper.  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
     September 30, 2003, ComEd's sublimit was $100 million.  The credit facility
     is used  principally  to  support  ComEd's  commercial  paper  program.  At
     September 30, 2003, ComEd had no commercial paper outstanding. For the nine
     months ended September 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  September  30, 2003. At
     September  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, PECO, Generation and BSC may participate in the
     money pool as lenders and borrowers,  and Exelon  Corporate may participate
     as a lender. Funding of, and borrowings from, the money pool are predicated
     on whether such funding results in mutual economic  benefits to each of the
     participants. 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 nine months
     ended September 30, 2003, ComEd had various  investments in the money pool.
     The maximum amount of  outstanding


                                      121
<PAGE>

     investments  at any time during 2003 was $344 million.  As of September 30,
     2003, ComEd's  investment in the money pool was $147 million.  For the nine
     months ended September 30, 2003, ComEd earned $2 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 is precluded from lending or extending  credit
     or indemnity to Exelon and can only pay dividends  from retained or current
     earnings.  Furthermore,  a significant loss recorded at ComEd may limit the
     dividends  that  ComEd  can  distribute  to  Exelon.  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 transitional trust notes). At September
     30, 2003, ComEd had retained earnings of $836 million and its common equity
     ratio was 47%.  Long-term debt included $1.7 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 September 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



                                      122
<PAGE>

          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 $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 and has made
          refundable  prepayments of $11 million for potential  fess  associated
          with these  agreements.  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,  ultimate  net cash
          flows to ComEd related to these  agreements will either be positive or
          neutral  depending  upon the outcome of the refund claim with the IRS.
          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 12 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 9 of the Condensed  Combined Notes to Consolidated  Financial
          Statements for the commercial  commitments table 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.


                                      123
<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  September  30, 2003  Compared to Three  Months  Ended
     September 30, 2002

     Significant Operating Trends - PECO

<TABLE>
<CAPTION>
                                                             Three Months Ended September 30,
                                                             --------------------------------
                                                                            2003         2002     Variance     % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                    <C>            <C>          <C>           <C>
     OPERATING REVENUES                                                $   1,149      $ 1,224      $   (75)      (6.1%)

     OPERATING EXPENSES
         Purchased power                                                     482          509          (27)      (5.3%)
         Fuel                                                                 28           40          (12)     (30.0%)
         Operating and maintenance                                           192          140           52       37.1%
         Depreciation and amortization                                       134          127            7        5.5%
         Taxes other than income                                              12           85          (73)     (85.9%)
     -----------------------------------------------------------------------------------------------------
              Total operating expenses                                       848          901          (53)      (5.9%)
     -----------------------------------------------------------------------------------------------------

     OPERATING INCOME                                                        301          323          (22)      (6.8%)
     -----------------------------------------------------------------------------------------------------

     OTHER INCOME AND DEDUCTIONS
         Interest expense                                                    (73)         (93)          20      (21.5%)
         Interest expense to affiliate                                        (2)          --           (2)       n.m.
         Distributions on mandatorily redeemable preferred securities         (1)          (2)           1      (50.0%)
         Other, net                                                          (10)           5          (15)       n.m.
     -----------------------------------------------------------------------------------------------------
              Total other income and deductions                              (86)         (90)           4       (4.4%)
     -----------------------------------------------------------------------------------------------------

     INCOME BEFORE INCOME TAXES                                              215          233          (18)      (7.7%)

     INCOME TAXES                                                             74           76           (2)      (2.6%)
     -----------------------------------------------------------------------------------------------------

     NET INCOME                                                              141          157          (16)     (10.2%)
     Preferred stock dividends                                                (1)          (2)           1      (50.0%)
     -----------------------------------------------------------------------------------------------------

     NET INCOME ON COMMON STOCK                                        $     140      $   155      $   (15)      (9.7%)
     =====================================================================================================
<FN>
     n.m. - not meaningful
</FN>
</TABLE>


                                      124
<PAGE>

     Net Income
              Net income on common stock decreased $15 million,  or 10%, for the
     three  months  ended  September  30, 2003 as compared to the same period in
     2002. The decrease was a result of lower sales volume,  unfavorable weather
     conditions,  increased O&M related to storm-related  damage, and The Exelon
     Way  severance  costs,  partially  offset  by  lower  other  operating  and
     maintenance expenses, taxes other than income and interest expense on debt.

     Operating Revenue
              PECO's electric sales statistics were as follows:

<TABLE>
<CAPTION>
                                                    Three Months Ended September 30,
                                                    --------------------------------
     Retail Deliveries - (in GWhs)                            2003              2002         Variance         % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                          <C>               <C>                <C>            <C>
     Bundled Deliveries (1)
     Residential                                             3,333             3,422              (89)           (2.6%)
     Small Commercial & Industrial                           1,753             2,066             (313)          (15.2%)
     Large Commercial & Industrial                           4,013             4,006                7             0.2%
     Public Authorities & Electric Railroads                   217               224               (7)           (3.1%)
     -------------------------------------------------------------------------------------------------
                                                             9,316             9,718             (402)           (4.1%)
     -------------------------------------------------------------------------------------------------
     Unbundled Deliveries (2)
     Residential                                               258               371             (113)          (30.5%)
     Small Commercial & Industrial                             520               154              366             n.m.
     Large Commercial & Industrial                             208               236              (28)          (11.9%)
     Public Authorities & Electric Railroads (3)                --                --               --              --
     -------------------------------------------------------------------------------------------------
                                                               986               761              225            29.6%
     -------------------------------------------------------------------------------------------------
     Total Retail Deliveries                                10,302            10,479             (177)           (1.7%)
     =================================================================================================
<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.
</FN>
</TABLE>


                                      125
<PAGE>


<TABLE>
<CAPTION>
                                                    Three Months Ended September 30,
                                                    --------------------------------
     Electric Revenue                                         2003              2002         Variance         % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                       <C>              <C>               <C>                <C>
     Bundled Revenue (1)
     Residential                                          $    466         $     478         $    (12)          (2.5%)
     Small Commercial & Industrial                             211               251              (40)         (15.9%)
     Large Commercial & Industrial                             292               296               (4)          (1.4%)
     Public Authorities & Electric Railroads                    19                21               (2)          (9.5%)
     -------------------------------------------------------------------------------------------------
                                                               988             1,046              (58)          (5.5%)
     -------------------------------------------------------------------------------------------------
     Unbundled Revenue (2)
     Residential                                                20                32              (12)         (37.5%)
     Small Commercial & Industrial                              28                 9               19            n.m.
     Large Commercial & Industrial                               5                 7               (2)         (28.6%)
     Public Authorities & Electric Railroads (3)                --                --               --              --
     -------------------------------------------------------------------------------------------------
                                                                53                48                5           10.4%
     -------------------------------------------------------------------------------------------------
     Total Electric Retail Revenues                          1,041             1,094              (53)          (4.8%)
     Wholesale and Miscellaneous Revenue (4)                    55                63               (8)         (12.7%)
     -------------------------------------------------------------------------------------------------
     Total Electric Revenue                               $  1,096         $   1,157         $    (61)          (5.3%)
     =================================================================================================
<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>

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

<TABLE>
<CAPTION>
                                                                                                               Variance
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                                                             <C>
     Rate mix                                                                                                   $   (21)
     Weather                                                                                                        (18)
     Customer choice                                                                                                (14)
     Volume                                                                                                           1
     Other effects                                                                                                   (1)
     -------------------------------------------------------------------------------------------------------------------
     Retail revenue                                                                                             $   (53)
     ===================================================================================================================
</TABLE>

     o    Rate Mix. The decrease in revenues  from rate mix is due to changes in
          monthly usage patterns in all customer classes during the three months
          ended September 30, 2003 as compared to the same period in 2002.
     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  summer
          weather during the quarter. Cooling degree-days decreased 11%.
     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.

                                      126
<PAGE>

               For the  three  months  ended  September  30,  2003,  the  energy
          provided by  alternative  suppliers was 986 GWhs, or 9.6%, as compared
          to 761 GWhs, or 7.3%,  for the three months ended  September 30, 2002.
          As  of  September  30,  2003,  the  number  of  customers   served  by
          alternative  suppliers was 297,821,  or 19.6%, as compared to 285,549,
          or 18.7%, as of September 30, 2002.
               The PUC's Final Electric  Restructuring  Order established 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.  In
          September  2003,  the auction for the second phase of the  residential
          customer MST plan resulted in two winning  bidders who were awarded an
          aggregate of 267,000  residential  customers.  The selected  customers
          will be  transferred  during  December  2003.  No renewable  bids were
          received for any customers.  Any customer transferred has 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, higher delivery volume affected
          PECO's  revenue  by $1  million  compared  to the same  period in 2002
          primarily  related  to  decreases  in usage by the  residential  class
          offset by an increase in usage by the small  commercial and industrial
          class.


                                      127
<PAGE>

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

<TABLE>
<CAPTION>
                                                             Three Months Ended September 30,
                                                             --------------------------------
     Deliveries to customers in mmcf                                        2003         2002     Variance     % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                        <C>          <C>           <C>        <C>
     Retail sales                                                          3,498        3,805         (307)      (8.1%)
     Transportation                                                        6,012        7,542       (1,530)     (20.3%)
     -----------------------------------------------------------------------------------------------------
     Total                                                                 9,510       11,347       (1,837)     (16.2%)
     =====================================================================================================

                                                             Three Months Ended September 30,
                                                             --------------------------------
     Revenue                                                                2003         2002     Variance     % Change
     -------------------------------------------------------------------------------------------------------------------
     Retail sales                                                      $      47    $      43    $       4        9.3%
     Transportation                                                            4            5           (1)     (20.0%)
     Resales and other                                                         2           19          (17)     (89.5%)
     -----------------------------------------------------------------------------------------------------
     Total                                                             $      53     $     67    $     (14)     (20.9%)
     =====================================================================================================
</TABLE>

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

<TABLE>
<CAPTION>
                                                                                                               Variance
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                                                           <C>
     Rate changes                                                                                             $       6
     Volume                                                                                                          (2)
     -------------------------------------------------------------------------------------------------------------------
     Total gas retail revenues                                                                                $       4
     ===================================================================================================================
</TABLE>

     o    Rate Changes.  The favorable  variance in rate changes is attributable
          to increases of 15% and 7% 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  September 30,
          2003 was 18% 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.
     o    Volume.  Delivery volume was lower in the three months ended September
          30, 2003  compared to the same period in 2002 due to decreased  retail
          sales in all customer classes.

              The reduction in transportation volumes and revenues are primarily
     the result of lower intercompany  deliveries to Generation during the three
     months ended September 30, 2003 compared to the same period in 2002.

              Lower resale revenues are attributable to a decrease in off-system
     sales,  exchanges  and  capacity  releases  during the three  months  ended
     September 30, 2003 compared to the same period in 2002.

                                      128
<PAGE>

     Purchased Power
              Purchased  power expense for the three months ended  September 30,
     2003 decreased $27 million,  or 5%, as compared to the same period in 2002.
     The decrease in purchased  power expense was primarily  attributable to $11
     million of unfavorable  weather  conditions,  $11 million from customers in
     Pennsylvania  selecting an alternative  electric generation supplier and $9
     million related to lower PJM ancillary charges,  partially offset by higher
     delivery volumes of $3 million.

     Fuel
              Fuel  expense  for the  three  months  ended  September  30,  2003
     decreased $12 million, or 30%, as compared to the same period in 2002. This
     decrease was primarily  attributable to lower wholesale sales of gas of $17
     million, partially offset by higher gas prices and volumes of $4 million.

     Operating and Maintenance
              O&M  expense  for  the  three  months  ended  September  30,  2003
     increased $52 million,  or 37%, as compared to the same period in 2002. The
     increase  in O&M  expense  was  primarily  attributable  to $41  million of
     severance and related  postretirement  health and welfare benefits accruals
     and pension and postretirement curtailment costs associated with The Exelon
     Way,  $18  million  of higher  storm-related  costs,  $4  million of higher
     corporate  allocations,  and $2  million of higher  expense  related to the
     allowance for the uncollectible  accounts,  partially offset by $10 million
     of lower costs  associated  with the initial  implementation  of  automated
     meter  reading  services  in 2002  and a $7  million  decrease  in  payroll
     expense.

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

<TABLE>
<CAPTION>
                                                    Three Months Ended September 30,
                                                    --------------------------------
                                                              2003              2002         Variance          % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                         <C>            <C>               <C>                   <C>
     Competitive transition charge amortization             $   96         $      90         $      6              6.7%
     Depreciation expense                                       33                31                2              6.5%
     Other amortization expense                                  5                 6               (1)          (16.7%)
     -------------------------------------------------------------------------------------------------
     Total depreciation and amortization                    $  134         $     127         $      7              5.5%
     =================================================================================================
</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  September  30,
     2003 decreased $73 million, or 86%, as compared to the same period in 2002.
     The  decrease  was  primarily  attributable  to $58 million  related to the
     reversal of real estate tax accruals  during the third  quarter of 2003, $9
     million related to 2002 real estate tax expense, $3 million related to 2002
     capital  stock tax and $3 million of lower  gross  receipts  tax related to
     lower revenues.

                                      129
<PAGE>

     Interest Charges
              Interest charges consist of interest expense,  interest expense to
    affiliate and distributions on mandatorily  redeemable preferred securities.
    Interest  charges  decreased $19 million,  or 20%, in the three months ended
    September 30, 2003 as compared to the same period in 2002.  The decrease was
    primarily  attributable  to lower interest  expense on long-term debt of $10
    million as a result of less  outstanding  debt and  refinancing  of existing
    debt at lower rates,  and a reversal of accrued  interest expense on federal
    income taxes of $8 million.

     Other, Net
              Other,  net  decreased  income by $15 million in the three  months
     ended  September  30,  2003 as  compared  to the same  period in 2002.  The
     decrease was  attributable to reversal of interest income on federal income
     taxes.

     Income Taxes
              The  effective  tax rate was  34.4%  for the  three  months  ended
     September  30, 2003 as  compared to 32.6% 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 September 30,
     2003 were consistent as compared to the same period in 2002.

                                      130
<PAGE>

     Nine  Months  Ended  September  30,  2003  Compared  to Nine  Months  Ended
     September 30, 2002

     Significant Operating Trends - PECO

<TABLE>
<CAPTION>
                                                              Nine Months Ended September 30,
                                                              -------------------------------
                                                                            2003         2002     Variance     % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                    <C>            <C>          <C>            <C>
     OPERATING REVENUES                                                $   3,328      $ 3,239      $    89        2.7%

     OPERATING EXPENSES
         Purchased power                                                   1,290        1,265           25        2.0%
         Fuel                                                                285          228           57       25.0%
         Operating and maintenance                                           453          407           46       11.3%
         Depreciation and amortization                                       370          348           22        6.3%
         Taxes other than income                                             123          207          (84)     (40.6%)
     -----------------------------------------------------------------------------------------------------
              Total operating expenses                                     2,521        2,455           66        2.7%
     -----------------------------------------------------------------------------------------------------

     OPERATING INCOME                                                        807          784           23        2.9%
     -----------------------------------------------------------------------------------------------------

     OTHER INCOME AND DEDUCTIONS
         Interest expense                                                   (241)        (280)          39      (13.9%)
         Interest expense to affiliate                                        (2)          --           (2)       n.m.
         Distributions on mandatorily redeemable preferred securities         (6)          (7)           1      (14.3%)
         Other, net                                                           --            7           (7)       n.m.
     -----------------------------------------------------------------------------------------------------
              Total other income and deductions                             (249)        (280)          31      (11.1%)
     -----------------------------------------------------------------------------------------------------

     INCOME BEFORE INCOME TAXES                                              558          504           54       10.7%

     INCOME TAXES                                                            193          166           27       16.3%
     -----------------------------------------------------------------------------------------------------

     NET INCOME                                                              365          338           27        8.0%
     Preferred stock dividends                                                (4)          (6)           2      (33.3%)
     -----------------------------------------------------------------------------------------------------

     NET INCOME ON COMMON STOCK                                        $     361      $   332      $    29        8.7%
     =====================================================================================================
<FN>
     n.m. - not meaningful
</FN>
</TABLE>

     Net Income
              Net income on common stock  increased $29 million,  or 9%, for the
     nine  months  ended  September  30,  2003 as compared to the same period in
     2002. The increase was a result of higher sales volume,  favorable  weather
     conditions,  lower interest expense and taxes other than income,  partially
     offset by increased O&M resulting from storm-related damage, and The Exelon
     Way  severance   costs,   increased   income  taxes  and  depreciation  and
     amortization expense.

                                      131
<PAGE>

     Operating Revenue
              PECO's electric sales statistics were as follows:

<TABLE>
<CAPTION>
                                                     Nine Months Ended September 30,
                                                     -------------------------------
     Retail Deliveries  (in GWhs)                             2003              2002         Variance         % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                          <C>               <C>              <C>              <C>
     Bundled Deliveries (1)
     Residential                                             8,723             7,592            1,131            14.9%
     Small Commercial & Industrial                           5,065             5,704             (639)         (11.2%)
     Large Commercial & Industrial                          11,190            11,285              (95)          (0.8%)
     Public Authorities & Electric Railroads                   692               617               75           12.2%
     -------------------------------------------------------------------------------------------------
                                                            25,670            25,198              472            1.9%
     -------------------------------------------------------------------------------------------------
     Unbundled Deliveries (2)
     Residential                                               708             1,720           (1,012)         (58.8%)
     Small Commercial & Industrial                           1,044               253              791            n.m.
     Large Commercial & Industrial                             610               351              259           73.8%
     Public Authorities & Electric Railroads (3)                --                --               --           --
     -------------------------------------------------------------------------------------------------
                                                             2,362             2,324               38            1.6%
     -------------------------------------------------------------------------------------------------
     Total Retail Deliveries                                28,032            27,522              510            1.9%
     =================================================================================================
<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.
</FN>
</TABLE>


<TABLE>
<CAPTION>
                                                     Nine Months Ended September 30,
                                                     -------------------------------
     Electric Revenue                                         2003              2002         Variance         % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                       <C>              <C>               <C>                <C>
     Bundled Revenue (1)
     Residential                                          $  1,122         $     999         $    123           12.3%
     Small Commercial & Industrial                             585               664              (79)         (11.9%)
     Large Commercial & Industrial                             825               829               (4)          (0.5%)
     Public Authorities & Electric Railroads                    62                58                4            6.9%
     -------------------------------------------------------------------------------------------------
                                                             2,594             2,550               44            1.7%
     -------------------------------------------------------------------------------------------------
     Unbundled Revenue (2)
     Residential                                                52               129              (77)         (59.7%)
     Small Commercial & Industrial                              54                13               41            n.m.
     Large Commercial & Industrial                              16                10                6           60.0%
     Public Authorities & Electric Railroads (3)                --                --               --              --
     -------------------------------------------------------------------------------------------------
                                                               122               152              (30)         (19.7%)
     -------------------------------------------------------------------------------------------------
     Total Electric Retail Revenues                          2,716             2,702               14            0.5%
     Wholesale and Miscellaneous Revenue (4)                   164               179              (15)          (8.4%)
     -------------------------------------------------------------------------------------------------
     Total Electric Revenue                               $  2,880         $   2,881         $     (1)             --
     =================================================================================================
<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>


                                      132
<PAGE>

              The changes in electric  retail revenues for the nine months ended
     September  30,  2003,  as  compared  to the same  period  in 2002,  were as
     follows:

<TABLE>
<CAPTION>
                                                                                                               Variance
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                                                             <C>
     Volume                                                                                                     $    37
     Weather                                                                                                          8
     Rate Mix                                                                                                       (28)
     Customer choice                                                                                                 (3)
     -------------------------------------------------------------------------------------------------------------------
     Retail revenue                                                                                             $    14
     ===================================================================================================================

</TABLE>

     o    Volume.  Exclusive of weather impacts, higher delivery volume affected
          PECO's  revenue by $37  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 summer
          weather.  Heating  degree-days  increased 35% and cooling  degree-days
          decreased 19% for the nine months ended September 30, 2003 compared to
          the same period in 2002.
     o    Rate Mix. The decrease in revenues  from rate mix is due to changes in
          monthly usage patterns in all customer classes during the nine  months
          ended September 30, 2003 as 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 nine months ended September 30, 2003, the energy provided
          by alternative suppliers was 2,362 GWhs, or 8.4%, as compared to 2,324
          GWhs,  or 8.4%,  for the nine months ended  September  30, 2002. As of
          September  30,  2003,  the number of customers  served by  alternative
          suppliers was 297,821,  or 19.6%, as compared to 285,549, or 18.7%, as
          of September 30, 2002.

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

<TABLE>
<CAPTION>
                                                              Nine Months Ended September 30,
                                                              -------------------------------
     Deliveries to customers in mmcf                                        2003         2002     Variance     % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                       <C>          <C>          <C>          <C>
     Retail sales                                                         44,183       34,128       10,055       29.5%
     Transportation                                                       19,954       22,862       (2,908)     (12.7%)
     -----------------------------------------------------------------------------------------------------
     Total                                                                64,137       56,990        7,147       12.5%
     =====================================================================================================

                                                              Nine Months Ended September 30,
                                                              -------------------------------
     Revenue                                                                2003         2002     Variance     % Change
     -------------------------------------------------------------------------------------------------------------------
     Retail sales                                                      $     418    $     309    $     109       35.3%
     Transportation                                                           14           15           (1)      (6.7%)
     Resales and other                                                        16           34          (18)     (52.9%)
     -----------------------------------------------------------------------------------------------------
     Total                                                             $     448     $    358     $     90       25.1%
     =====================================================================================================
</TABLE>

                                      133
<PAGE>

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

<TABLE>
<CAPTION>
                                                                                                               Variance
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                                                           <C>
     Weather                                                                                                  $      73
     Volume                                                                                                          21
     Rate changes                                                                                                    15
     -------------------------------------------------------------------------------------------------------------------
     Total gas retail revenue                                                                                 $     109
     ===================================================================================================================
</TABLE>

     o    Weather.  The weather impact was favorable  compared to the prior year
          as a result of colder winter weather.  Heating  degree-days  increased
          35% in the nine months ended  September  30, 2003 compared to the same
          period in 2002. Retail sales deliveries increased  approximately 8,600
          mmcf due to the colder weather.
     o    Volume. Exclusive of weather impacts, higher delivery volume increased
          revenue in the nine months ended  September  30, 2003  compared to the
          same  period in 2002  resulting  from  increased  retail  sales in all
          classes.  Deliveries to retail customers increased approximately 1,500
          mmcf,  or 4% in the nine months ended  September  30, 2003 compared to
          the same period in 2002.
     o    Rate  Changes.  The  favorable  variance in rates is  attributable  to
          increases of 15% and 7% in the  purchased  gas  adjustment  by the PUC
          effective  March 1, 2003 and June 1, 2003,  respectively.  The average
          rate per mmcf for the nine  months  ended  September  30,  2003 was 5%
          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.

              The reduction in transportation volumes and revenues are primarily
     the result of lower  intercompany  deliveries to Generation during the nine
     months ended September 30, 2003 compared to the same period in 2002.

              Lower resale revenues are attributable to a decrease in off-system
     sales,  exchanges  and  capacity  releases  during  the nine  months  ended
     September 30, 2003 compared to the same period in 2002.

     Purchased Power
              Purchased  power  expense for the nine months ended  September 30,
     2003 increased $25 million,  or 2%, as compared to the same period in 2002.
     The increase in purchased  power expense was primarily  attributable to $24
     million of higher electric delivery volume and $2 million related to higher
     PJM ancillary charges.

     Fuel
              Fuel  expense  for  the  nine  months  ended  September  30,  2003
     increased $57 million, or 25%, as compared to the same period in 2002. This
     increase was  primarily  attributable  to $50 million of favorable  weather
     conditions,  $15  million  from higher gas prices and $11 million of higher
     delivery volumes, partially offset by $24 million in reductions from resale
     transactions.

                                      134
<PAGE>

     Operating and Maintenance
              O&M expense for the nine months ended September 30, 2003 increased
     $46 million, or 11% as compared to the same period in 2002. The increase in
     O&M expense was  primarily  attributable  to $41 million of  severance  and
     related postretirement health and welfare benefits accruals and pension and
     postretirement  curtailment  costs  associated  with The  Exelon  Way,  $22
     million of higher  storm-related  costs, $12 million of increased  employee
     fringe benefits,  partially offset by $23 million of lower costs associated
     with the initial  implementation  of automated  meter  reading  services in
     2002,   $7  million  of  lower   expense   related  to  the  allowance  for
     uncollectible accounts and $6 million of additional miscellaneous other net
     positive impacts.

     Depreciation and Amortization
              Depreciation  and  amortization  expense for the nine months ended
     September 30, 2003  increased  $22 million,  or 6%, as compared to the same
     period in 2002 as follows:

<TABLE>
<CAPTION>
                                                     Nine Months Ended September 30,
                                                     -------------------------------
                                                              2003              2002         Variance          % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                         <C>            <C>               <C>                   <C>
     Competitive transition charge amortization             $  256         $     236         $     20              8.5%
     Depreciation expense                                       99                94                5              5.3%
     Other amortization expense                                 15                18               (3)          (16.7%)
     -------------------------------------------------------------------------------------------------
     Total depreciation and amortization                    $  370         $     348         $     22              6.3%
     =================================================================================================
</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 nine months  ended  September  30,
     2003 decreased $84 million, or 41%, as compared to the same period in 2002.
     The decrease was primarily  attributable to a $58 million  reversal of real
     estate  tax  accruals  during  the third  quarter  of 2003,  a $12  million
     reversal  of the use  tax  accrual  due to an  audit  settlement  and a $12
     million decrease in 2003 real estate tax expense.

     Interest Charges
              Interest charges consist of interest expense,  interest expense to
     affiliates   and   distributions   on  mandatorily   redeemable   preferred
     securities.  Interest  charges  decreased $38 million,  or 13%, in the nine
     months ended September 30, 2003 as compared to the same period in 2002. The
     decrease was primarily  attributable to lower interest expense on long-term
     debt of $28  million  as a  result  of  scheduled  principal  payments  and
     refinancing  of  existing  debt at lower  interest  rates and an $8 million
     reversal of accrued interest expense on federal income taxes.

     Other, Net
              Other, net decreased $7 million in the nine months ended September
     30, 2003 as compared to the same period in 2002. The decrease was primarily
     attributable  to reversal of interest income on federal income taxes of $14
     million,  partially  offset by $4 million related to higher interest income
     and the favorable settlement of a customer contract of $3 million.

                                      135
<PAGE>

     Income Taxes
              The  effective  tax  rate was  34.6%  for the  nine  months  ended
     September  30, 2003 as  compared to 32.9% 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 nine months ended September 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,
     participation in the intercompany money pool 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.

              As  part  of  the  implementation  of The  Exelon  Way,  PECO  has
    identified 140 positions for  elimination by the end of 2004 and anticipates
    identifying  additional  positions for  elimination  in 2005 and 2006.  PECO
    recorded a charge for cash severance of $13 million during the third quarter
    2003,  which  PECO  anticipates  will be paid by  December  31,  2004.  PECO
    anticipates  incurring  further  costs  associated  with The Exelon Way upon
    identifying  additional  positions  to be  eliminated.  These  costs will be
    recorded in the period in which the costs can be reasonably estimated.

                                      136
<PAGE>

     Cash Flows from Operating Activities

              Cash  flows  provided  by  operations  for the nine  months  ended
     September   30,  2003  and  2002  were  $757  million  and  $473   million,
     respectively.  The increase in cash flows was primarily  attributable  to a
     $300 million  increase in working capital and by a $27 million  increase in
     net income,  partially  offset by an $83 million change in deferred  energy
     costs.  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, customer choice and future regulatory proceedings 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 nine months ended
     September   30,  2003  and  2002  were  $193  million  and  $177   million,
     respectively.  The increase in cash flows used in investing  activities was
     primarily attributable to an increase in capital expenditures.

              PECO's projected  capital  expenditures for 2003 are $272 million.
     Approximately  60% of the budgeted  2003  expenditures  are for  continuing
     efforts  to  further  improve  the  reliability  of  its  transmission  and
     distribution systems. The remainder is for capital additions to support new
     business  and  customer   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.

                                      137
<PAGE>

     Cash Flows from Financing Activities

              Cash flows used in financing  activities for the nine months ended
     September   30,  2003  and  2002  were  $545  million  and  $214   million,
     respectively.  Cash  flows  used  in  financing  activities  are  primarily
     attributable  to debt  service  and  payment of  dividends  to Exelon.  The
     increase  in  cash  flows  used  in  financing   activities   is  primarily
     attributable to increased debt and preferred securities redemptions of $681
     million,  partially  offset by  additional  issuances of long-term  debt of
     $328. See Note 12 of the Condensed Combined Notes to Consolidated Financial
     Statements for further discussion of PECO's debt financing activities.  For
     the nine months ended  September 30, 2003, PECO paid Exelon $244 million in
     common  stock  dividends  compared  to $255  million for the same period in
     2002.

     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 September 30, 2003,  PECO's sublimit was
     $400 million.  The credit  facility is used by PECO  principally to support
     its commercial paper program.  At September 30, 2003,  PECO's  Consolidated
     Balance Sheet reflected $12 million in commercial  paper  outstanding.  For
     the nine months ended  September  30, 2003,  the average  interest  rate on
     notes payable was approximately 1.25%.

              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  September  30, 2003. At
     September  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, PECO, Generation and BSC may participate in the
     money pool as lenders and borrowers,  and Exelon  Corporate may participate
     as a lender. Funding of, and borrowings from, the money pool are predicated
     on whether such funding results in mutual economic  benefits to each of 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 nine months ended September 30, 2003,  PECO had various  investments in
     the money pool. The maximum  amount of outstanding  investments at any time
     during  2003 was $59  million.  As of  September  30,  2003,  there  was no
     outstanding  investment  balance.  For the nine months ended  September 30,
     2003, PECO earned less than $1 million in interest.

                                      138
<PAGE>

              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 is precluded from lending or extending credit or
     indemnity  to Exelon and can pay  dividends  only from  retained or current
     earnings.  At  September  30,  2003,  PECO had  retained  earnings  of $517
     million.

              Long-term debt included $4 billion of transition bonds.

     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 September 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 and has made  refundable
          prepayments  of $1 million for potential  fees  associated  with these
          agreements.  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,  ultimate  net cash flows to
          PECO  related to these  agreements  will either be positive or neutral
          depending  upon the  outcome of the refund  claim with the IRS.  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 12 of the Condensed Combined Notes to Consolidated  Financial
          Statements for further  discussion of material  changes in PECO's debt
          and preferred securities  obligations from those set forth in the 2002
          Form 10-K.

     o    See Note 9 of the Condensed  Combined Notes to Consolidated  Financial
          Statements for the commercial  commitments table  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.

                                      139
<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  September  30, 2003  Compared to Three  Months  Ended
     September 30, 2002

     Significant Operating Trends - Generation
<TABLE>
<CAPTION>
                                                             Three Months Ended September 30,
                                                             --------------------------------
                                                                            2003         2002     Variance     % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                    <C>            <C>          <C>           <C>
     OPERATING REVENUES                                                $   2,537      $ 2,213      $   324       14.6%

     OPERATING EXPENSES
         Purchased power                                                   1,240        1,257          (17)      (1.4%)
         Fuel                                                                449          273          176       64.5%
         Impairment of Exelon Boston Generating, LLC                         945           --          945        n.m.
         Operating and maintenance                                           530          391          139       35.5%
         Depreciation and amortization                                        51           68          (17)     (25.0%)
         Taxes other than income                                              28           37           (9)     (24.3%)
     -----------------------------------------------------------------------------------------------------
              Total operating expenses                                     3,243        2,026        1,217       60.1%
     -----------------------------------------------------------------------------------------------------

     OPERATING INCOME (LOSS)                                                (706)         187         (893)       n.m.
     -----------------------------------------------------------------------------------------------------

     OTHER INCOME AND DEDUCTIONS
         Interest expense                                                    (25)         (23)          (2)       8.7%
         Equity in earnings of unconsolidated affiliates                      53           87          (34)     (39.1%)
         Other, net                                                          (30)          14          (44)       n.m.
     -----------------------------------------------------------------------------------------------------
              Total other income and deductions                               (2)          78          (80)    (102.6%)
     -----------------------------------------------------------------------------------------------------

     INCOME (LOSS) BEFORE INCOME TAXES                                      (708)         265         (973)       n.m.

     INCOME TAXES                                                           (280)         102         (382)       n.m.
     -----------------------------------------------------------------------------------------------------

     NET INCOME (LOSS)                                                 $    (428)     $   163      $  (591)       n.m.
     =====================================================================================================
<FN>
     n.m. - not meaningful
</FN>
</TABLE>

     Net Income (Loss)
              Generation's  net income  decreased  by $591 million for the three
     months  ended  September  30,  2003  compared  to the same  period  in 2002
     primarily  due to a $945  million  ($573  million,  net  of  income  taxes)
     impairment  charge  related to  Generation's  long-lived  assets in EBG, an
     additional $55 million ($36 million, net of income taxes) impairment charge
     related to Generation's  investment in Sithe, and $46 million ($30 million,
     net of income taxes) due to severance and related postretirement health and
     welfare benefits accruals and pension and postretirement  curtailment costs
     associated with The Exelon Way. The decrease was partially offset by a $165
     million  increase in revenue,  net of purchased  power and fuel. Net income
     (loss)  was  additionally  affected  by a net  decrease  in the  equity  in
     earnings of unconsolidated affiliates.

                                      140
<PAGE>

     Operating Revenues
              Revenues  increased by $324  million,  or 15% for the three months
     ended September 30, 2003 compared to the same period in 2002. For the three
     months  ended  September  30,  2003 and 2002,  Generation's  sales  were as
     follows:

<TABLE>
<CAPTION>
                                                             Three Months Ended September 30,
                                                             --------------------------------
     Revenue (in millions)                                                  2003         2002     Variance     % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                    <C>          <C>          <C>             <C>
     Energy Delivery and Exelon Energy Company                         $   1,338    $   1,461    $    (123)      (8.4%)
     Market Sales                                                          1,138          752          386       51.3%
     -----------------------------------------------------------------------------------------------------
     Total Energy Sales Revenue                                            2,476        2,213          263       11.9%
     Trading Portfolio                                                         1          (12)          13     (108.3%)
     Other Revenue                                                            60           12           48        n.m.
     -----------------------------------------------------------------------------------------------------
     Total Revenue                                                     $   2,537    $   2,213    $     324       14.6%
     =====================================================================================================

                                                             Three Months Ended September 30,
                                                             --------------------------------
     Sales (in GWhs)                                                        2003         2002     Variance     % Change
     -------------------------------------------------------------------------------------------------------------------
     Energy Delivery and Exelon Energy Company                            32,237       35,996       (3,759)     (10.4%)
     Market Sales                                                         29,613       21,177        8,436       39.8%
     -----------------------------------------------------------------------------------------------------
     Total Sales                                                          61,850       57,173        4,677        8.2%
     =====================================================================================================
</TABLE>

              Trading  volumes  of  11,086  GWhs and  28,455  GWhs for the three
     months ended September 30, 2003 and 2002, respectively, are 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 September 30, 2003 and 2002 is as follows:

<TABLE>
<CAPTION>
                                                                       Three Months Ended September 30,
                                                                       --------------------------------
      ($/MWh)                                                                   2003               2002        % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                      <C>              <C>                     <C>
     Average Revenue
         Energy Delivery and Exelon Energy Company                       $     41.51      $      40.56            2.3%
         Market Sales                                                          38.43             35.50            8.3%
         Total - excluding the trading portfolio                               40.03             38.69            3.5%
     -------------------------------------------------------------------------------------------------------------------
</TABLE>

                Energy  Delivery  and  Exelon  Energy  Company.  Sales to Energy
     Delivery decreased by $102 million primarily due to unfavorable  weather in
     ComEd  and  PECO's  service  territories  during  the  three  months  ended
     September  30,  2003  compared  to the same  period  in 2002.  Generation's
     average revenue per MWh was affected by increased  weighted  average on and
     off-peak prices per MWh for supply agreements with ComEd and PECO. Sales to
     Exelon  Energy  Company  decreased  $21 million for the three  months ended
     September 30, 2003 compared to the same period in 2002 primarily due to the
     discontinuance of Exelon Energy Company operations in the PJM region.





                                      141
<PAGE>

              Market   Sales.   The  increase  in  market  sales  was  primarily
     attributable to a $227 million increase resulting from increased production
     from  generating  assets  acquired  during 2002. In addition,  market sales
     increased $149 million as a result of favorable  market  prices,  primarily
     driven by increased  fossil fuel prices,  and a $19 million increase due to
     lower load requirements to affiliates.

              Trading Revenues. Trading activity increased revenue by $1 million
     during the three months ended  September 30, 2003 compared to a $12 million
     decrease  for the same  period in 2002 due to  reduced  trading  volume and
     overall portfolio performance improvement in 2003.

              Other  Revenues.   Other  revenues  increased   primarily  due  to
     increases  in natural gas market  sales.  As a result of natural gas supply
     contracts  assigned  to  Generation  with  the  2002  asset   acquisitions,
     Generation had an excess supply of natural gas. Other revenues also include
     nuclear decommissioning cost recoveries from ComEd and PECO.

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

<TABLE>
<CAPTION>
                                                              Three Months Ended September 30,
                                                              --------------------------------
     Supply of Sales (in GWhs)                                              2003         2002     Variance     % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                      <C>          <C>             <C>        <C>
     Nuclear Generation (1)                                               30,152       29,817          335        1.1%
     Purchases - non-trading portfolio (2)                                24,062       23,425          637        2.7%
     Fossil and Hydro Generation                                           7,636        3,931        3,705       94.3%
     -----------------------------------------------------------------------------------------------------
     Total Supply                                                         61,850       57,173        4,677        8.2%
     =====================================================================================================
<FN>
     (1) Excluding AmerGen.
     (2) Including PPAs with AmerGen.
</FN>
</TABLE>

<TABLE>
<CAPTION>
                                                                       Three Months Ended September 30,
                                                                       --------------------------------
      ($/MWh)                                                                   2003               2002      % Change
     -----------------------------------------------------------------------------------------------------------------
<S>                                                                     <C>               <C>                    <C>
     Average Supply Cost (1) - excluding trading portfolio               $     27.31       $     26.66            2.4%
     -----------------------------------------------------------------------------------------------------------------
<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  Exelon New  England  plants
          acquired in November  2002,  which in total account for an increase of
          3,570 GWhs, and
     o    Generation  entered into a new PPA with AmerGen in the second  quarter
          of 2003. As a result,  1,228 GWhs were  purchased from Oyster Creek in
          the third quarter of 2003.

              Purchased power decreased $17 million, or 1%, for the three months
     ended September 30, 2003 compared to the same period in 2002, primarily due
     to  the  positive   impact  of  the  Exelon  New  England  plants  becoming
     operational  during the three months ended  September  30, 2003 and reduced
     capacity  payments as a result of  releasing  Midwest  Generation  options.
     Generation's demand for counterparty purchased power was decreased due to a
     $29 million  increase in  purchased  power from  AmerGen as a result of the
     June 2003 PPA to purchase 100% of the output of Oyster Creek.  The decrease
     in  purchased  power  was  partially  offset  by  a  $18  million  loss  on
     mark-to-market  hedging  activity for the three months ended  September 30,
     2003 compared to no gain or loss in the same period in 2002.




                                      142
<PAGE>

              Fuel expense increased $176 million,  or 65%, for the three months
     ended September 30, 2003 compared to the same period in 2002, as summarized
     below:
<TABLE>
<CAPTION>
                                                              Three Months Ended September 30,
                                                              --------------------------------
      (in millions)                                                         2003         2002     Variance     % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                          <C>          <C>          <C>      <C>
     Nuclear Generation (1)                                            $     125    $     124    $       1        0.8%
     Fossil and Hydro Generation                                             324          149          175      117.4%
     -----------------------------------------------------------------------------------------------------
     Total                                                             $     449    $     273    $     176       64.5%
     =====================================================================================================
<FN>
     (1)  Excluding AmerGen
</FN>
</TABLE>

              This  increase was  primarily  due to a $154  million  increase in
     fossil  fuel  costs  for  generation  plant  assets  acquired  in 2002.  In
     addition,  fuel expense increased $10 million due to the write down of coal
     inventory as a result of a fuel burn  analysis and $8 million  increase due
     to increased emission allowance trade activity.

     Impairment of Exelon Boston Generating, LLC
              In connection with the decision to transition out of the ownership
     of EBG and the projects,  Generation recorded a long-lived asset impairment
     charge of $945 million ($573 million net of income taxes).

     Operating and Maintenance
              O&M expense  increased $139 million,  or 36%, for the three months
     ended  September 30, 2003 compared to the same period in 2002. The increase
     in O&M  expense was  primarily  attributable  to a $46 million  increase in
     severance and related  postretirement  health and welfare benefits accruals
     and pension and postretirement curtailment costs associated with The Exelon
     Way and $60 million of accretion expense related to SFAS No. 143. Accretion
     expense   includes  $39  million  of  accretion  of  the  asset  retirement
     obligation and $21 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.  For a  further  discussion  of SFAS No.  143,  see Note 2 of the
     Condensed Combined Notes to Consolidated  Financial  Statements.  Operating
     and  maintenance  expense also included $30 million of additional  expenses
     due to asset  acquisitions  made after the third  quarter of 2002,  and $15
     million of additional  employee payroll and benefits costs. These increases
     were partially offset by $9 million of lower nuclear refueling outage costs
     and $4 million reduction in other O&M costs.

<TABLE>
<CAPTION>
                                                                                       Three Months Ended September 30,
                                                                                       --------------------------------
                                                                                                   2003            2002
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                                       <C>              <C>
     Nuclear fleet capacity factor (1)                                                            95.3%           93.9%
     Nuclear fleet production cost per MWh (1)                                               $    11.69       $   12.40
     Average purchased power cost for wholesale operations per MWh (2)                       $    51.53       $   53.75
     -------------------------------------------------------------------------------------------------------------------
<FN>
     (1)  Including AmerGen and excluding Salem, which is operated by PSE&G.
     (2)  Including PPAs with AmerGen.
</FN>
</TABLE>

              The  higher  nuclear   capacity   factor  and  decreased   nuclear
     production  costs were primarily due to 16 fewer planned  refueling  outage
     days,  resulting  in a $9 million  decrease in outage  costs,  in the three
     months  ended  September  30,  2003 as compared to the same period in 2002.





                                      143
<PAGE>

     Additionally, the three months ended September 30, 2003 and 2002 included 9
     and 7 unplanned outages, respectively.

     Depreciation and Amortization
              Depreciation and amortization  expense  decreased $17 million,  or
     25%, for the three months ended  September 30, 2003 as compared to the same
     period in 2002.  The decrease was primarily  attributable  to a $29 million
     net reduction in decommissioning expense, net of ARC depreciation, 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.  These decreases were partially offset by $10 million of
     additional  depreciation  expense  on capital  additions  placed in service
     after  the  third  quarter  of  2002,  and  $7  million  related  to  plant
     acquisitions made after the third quarter of 2002. 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  $9  million,  or 24%,  for the
    three months ended  September  30, 2003  compared to the same period in 2002
    primarily  resulting from a $15 million  reduction to reserves  recorded for
    exposures  associated  with real estate  taxes.  This decrease was partially
    offset  by  a $7  million  increase  in  property  taxes  related  to  asset
    acquisitions made after the third quarter of 2002.

     Interest Expense
              Interest expense increased $2 million, or 9%, for the three months
     ended  September 30, 2003 compared to the same period in 2002. The increase
     was primarily due to $6 million of interest  expense on the long-term  debt
     obtained  as a part of the  Exelon New  England  asset  acquisition  and $2
     million of interest  expense on the $536  million  note  payable  issued to
     Sithe in November 2002.  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, and a $2 million increase
     in capitalized interest due to a change in capitalized interest rates.

     Equity in Earnings of Unconsolidated Affiliates
              Equity in  earnings of  unconsolidated  affiliates  decreased  $34
     million,  or 39%, for the three months ended September 30, 2003 compared to
     the same  period in 2002.  The  decrease  was partly  due to a $17  million
     decrease in  Generation's  equity earnings of AmerGen.  AmerGen's  earnings
     were  primarily  affected by  decreased  power sales due to changes in PPAs
     that resulted in lower prices in the summer  months and higher  expenses at
     AmerGen  related  to  severance  costs  associated  with  The  Exelon  Way.
     Conversely,  the change in PPAs resulted in higher prices in all non-summer
     months during 2003 as compared to 2002.  The decrease was also due to a $17
     million  decrease in  Generation's  equity in  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 at
     Sithe.

     Other, Net
              Other,  net  decreased  $44  million  for the three  months  ended
     September  30, 2003  compared to the same period in 2002.  The decrease was
     due to a $55  million  impairment  charge  as a result  of a change in fair




                                      144
<PAGE>

     value of Generation's  investment in Sithe.  This decrease was offset by $9
     million of 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 O&M expense.

     Income Taxes
              The effective income tax rate was 39.5% for the three months ended
     September  30, 2003  compared  to 38.5% for the same  period in 2002.  This
     increase  was  primarily  attributable  to the  impact of changes in income
     before taxes as a result of the  impairments  recorded in the third quarter
     related to Generation's investment in Sithe and long-lived assets of EBG.


     Nine  Months  Ended  September  30,  2003  Compared  to Nine  Months  Ended
     September 30, 2002

     Significant Operating Trends - Generation
<TABLE>
<CAPTION>
                                                              Nine Months Ended September 30,
                                                              -------------------------------
                                                                            2003         2002     Variance     % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                    <C>            <C>          <C>           <C>
     OPERATING REVENUES                                                $   6,301      $ 5,233      $ 1,068       20.4%

     OPERATING EXPENSES
         Purchased power                                                   2,881        2,581          300       11.6%
         Fuel                                                              1,156          706          450       63.7%
         Impairment of Exelon Boston Generating, LLC                         945           --          945       n.m.
         Operating and maintenance                                         1,473        1,234          239       19.4%
         Depreciation and amortization                                       142          197          (55)     (27.9%)
         Taxes other than income                                             115          126          (11)      (8.7%)
     -----------------------------------------------------------------------------------------------------
              Total operating expenses                                     6,712        4,844        1,868       38.6%
     -----------------------------------------------------------------------------------------------------

     OPERATING INCOME (LOSS)                                                (411)         389         (800)      n.m.
     -----------------------------------------------------------------------------------------------------

     OTHER INCOME AND DEDUCTIONS
         Interest expense                                                    (63)         (51)         (12)      23.5%
         Equity in earnings of unconsolidated affiliates                      90          119          (29)     (24.4%)
         Other, net                                                         (164)          54         (218)      n.m.
     -----------------------------------------------------------------------------------------------------
              Total other income and deductions                             (137)         122         (259)      n.m.
     -----------------------------------------------------------------------------------------------------

     INCOME (LOSS) BEFORE INCOME TAXES AND CUMULATIVE
         EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES                         (548)         511       (1,059)      n.m.

     INCOME TAXES                                                           (209)         198         (407)      n.m
     -----------------------------------------------------------------------------------------------------

     INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGES IN
       ACCOUNTING PRINCIPLES                                                (339)         313         (652)      n.m.

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

     NET INCOME (LOSS)                                                 $    (231)     $   326      $  (557)    (170.9%)
     =====================================================================================================
     n.m. - not meaningful

</TABLE>


     Net Income (Loss)
              Generation's  net income  decreased by $557 million,  or 171%, for
     the nine months  ended  September  30, 2003  compared to the same period in
     2002. Income before  cumulative effect of changes in accounting  principles
     decreased  by $652  million for the nine months  ended  September  30, 2003





                                      145
<PAGE>

     compared  to the same  period in 2002  primarily  due to the third  quarter
     impairment  charge for the  long-lived  assets of EBG of $945 million ($573
     million,  net of income taxes),  first and third quarter impairment charges
     for  Generation's  equity  investment in Sithe  totaling $255 million ($166
     million,  net of income taxes), and a $46 million charge ($30 million,  net
     of income  taxes) due to severance  and related  postretirement  health and
     welfare benefit accruals and pension and  postretirement  curtailment costs
     associated  with The Exelon Way. These  decreases were partially  offset by
     higher revenue  resulting from increased  market electric sales. Net income
     (loss) was additionally affected by a net decrease in equity in earnings of
     unconsolidated affiliates.

     Operating Revenues
              Revenues increased by $1,068 million,  or 20%, for the nine months
     ended  September 30, 2003 compared to the same period in 2002. For the nine
     months  ended  September  30,  2003 and 2002,  Generation's  sales  were as
     follows:

<TABLE>
<CAPTION>
                                                              Nine Months Ended September 30,
                                                              -------------------------------
     Revenue (in millions)                                                  2003         2002     Variance     % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                    <C>          <C>          <C>             <C>
     Energy Delivery and Exelon Energy Company                         $   3,180    $   3,299    $    (119)      (3.6%)
     Market Sales                                                          3,001        1,927        1,074       55.7%
     -----------------------------------------------------------------------------------------------------
     Total Energy Sales Revenue                                            6,181        5,226          955       18.3%
     -----------------------------------------------------------------------------------------------------
     Trading Portfolio                                                        (1)         (27)          26      (96.3%)
     Other Revenue                                                           121           34           87        n.m.
     -----------------------------------------------------------------------------------------------------
     Total Revenue                                                     $   6,301    $   5,233    $   1,068       20.4%
     =====================================================================================================

                                                              Nine Months Ended September 30,
                                                              -------------------------------
     Sales (in GWhs)                                                        2003         2002     Variance     % Change
     -------------------------------------------------------------------------------------------------------------------
     Energy Delivery and Exelon Energy Company                            89,700       94,646       (4,946)      (5.2%)
     Market Sales                                                         80,877       61,089       19,788       32.4%
     -----------------------------------------------------------------------------------------------------
     Total Sales                                                         170,577      155,735       14,842        9.5%
     =====================================================================================================
</TABLE>

              Trading volumes of 28,532 GWhs and 51,260 GWhs for the nine months
     ended  September 30, 2003 and 2002,  respectively,  are 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  revenues  (per MWh) on energy sales for the
     nine months ended September 30, 2003 and 2002 were as follows:

<TABLE>
<CAPTION>
                                                                         Nine Months Ended September 30,
                                                                         -------------------------------
      ($/MWh)                                                                   2003               2002        % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                      <C>              <C>                     <C>
     Average Revenue
         Energy Delivery and Exelon Energy Company                       $     35.45      $      34.86            1.7%
         Market Sales                                                          37.11             31.55           17.6%
         Total - excluding the trading portfolio                               36.24             33.56            8.0%
     -------------------------------------------------------------------------------------------------------------------
</TABLE>

              Energy  Delivery  and  Exelon  Energy  Company.  Sales  to  Energy
     Delivery decreased by $85 million as a result of a net overall reduction in
     volume demand that resulted from unfavorable weather and customers choosing
     alternative  suppliers under the customer choice program.  The decrease was





                                      146
<PAGE>

     partially  offset by increased  prices per MWh for supply  agreements  with
     ComEd and PECO. Sales to Exelon Energy Company decreased by $34 million for
     the nine months  ended  September  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 $1,074 million  resulted  primarily
     from increased  production from generating assets acquired during 2002, and
     from lower load  requirements  of affiliates  and higher  wholesale  market
     prices, primarily attributable to higher fossil fuel prices.
              Trading  Revenues.  Trading activity reduced revenue by $1 million
    during the nine months ended  September  30, 2003 compared to a reduction of
    $27 million during the same period in 2002 due to lower trading  activity in
    2003.
              Other  Revenues.   Other  revenues  increased   primarily  due  to
     increases  in natural gas market  sales.  As a result of natural gas supply
     contracts  assigned  to  Generation  with  the  2002  asset   acquisitions,
     Generation had an excess supply of natural gas. Other revenues also include
     nuclear decommissioning cost recoveries from ComEd and PECO.

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

<TABLE>
<CAPTION>
                                                              Nine Months Ended September 30,
                                                              -------------------------------
     Supply of Sales (in GWhs)                                              2003         2002     Variance     % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                     <C>          <C>           <C>          <C>
     Nuclear Generation (1)                                               89,101       86,127        2,974        3.5%
     Purchases - non-trading portfolio (2)                                63,435       59,496        3,939        6.6%
     Fossil and Hydro Generation                                          18,041       10,112        7,929       78.4%
     -----------------------------------------------------------------------------------------------------
     Total Supply                                                        170,577      155,735       14,842        9.5%
     =====================================================================================================
<FN>
     (1) Excluding AmerGen.
     (2) Including PPAs with AmerGen.
</FN>
</TABLE>

<TABLE>
<CAPTION>
                                                                         Nine Months Ended September 30,
                                                                         -------------------------------
      ($/MWh)                                                                   2003               2002        % Change
     ------------------------------------------------------------------------------------------------------------------
<S>                                                                      <C>               <C>                   <C>
     Average Supply Cost (1) - excluding trading portfolio               $     23.67       $     21.04           12.5%
     ------------------------------------------------------------------------------------------------------------------
<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 6,565 GWhs, and
     o    increased  quantity of purchased power at higher prices.  In addition,
          Generation  entered into a new PPA with AmerGen in the second  quarter
          of 2003. As a result,  2,481 GWhs were  purchased from Oyster Creek in
          the second and third quarters of 2003.

              Purchased  power  increased  $300  million,  or 12%,  for the nine
    months ended September 30, 2003 compared to the same period in 2002 due to a
    $339 million  increase  related to higher market prices and the commencement
    of Exelon New England commercial  operations  resulting in an additional $35
    million   increase.   The   increase  in  purchased   power  also   reflects
    mark-to-market  hedging  losses of $17  million  for the nine  months  ended
    September  30,  2003  compared to gains of $11 million in the same period in
    2002. The increase was partially offset by $114 million related to decreased
    volume and reduced capacity





                                      147
<PAGE>

     payments as a result of releasing Midwest Generation options.  Generation's
     demand for counterparty purchased power decreased $91 million because of an
     increase in purchased power from AmerGen due to a June 2003 PPA to purchase
     100% of the output of Oyster Creek.

              Fuel expense  increased $450 million,  or 64%, for the nine months
     ended September 30, 2003 compared to the same period in 2002, as summarized
     below:

<TABLE>
<CAPTION>
                                                               Nine Months Ended September 30,
                                                               -------------------------------
      (in millions)                                                         2003         2002     Variance     % Change
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                   <C>          <C>          <C>              <C>
     Nuclear Generation (1)                                            $     385    $     360    $      25        6.9%
     Fossil and Hydro Generation                                             771          346          425      122.8%
     -----------------------------------------------------------------------------------------------------
     Total                                                             $   1,156    $     706    $     450       63.7%
     =====================================================================================================
<FN>
(1)      Excluding AmerGen
</FN>
</TABLE>

              This  increase is primarily the result of increases in fossil fuel
     generation  required to meet increased market demand for energy,  operation
     of new base load plants in New England and increased  demand in all regions
     during the first quarter of 2003.  Fossil and other fuel expense  increased
     $415 million as a result of acquisitions  of generating  plants in 2002. In
     addition,  fuel expense  increased $10 million due to the writedown of coal
     inventory  as a  result  of a  fuel  burn  analysis  Nuclear  fuel  expense
     increased  $25  million,   including  $9  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.

     Impairment of Exelon Boston Generating, LLC
              In connection with the decision to transition out of the ownership
     of EBG and the projects,  Generation recorded a long-lived asset impairment
     charge of $945 million ($573 million net of income taxes).

     Operating and Maintenance
              O&M expense  increased  $239 million,  or 19%, for the nine months
     ended  September 30, 2003 compared to the same period in 2002. The increase
     in O&M expense was primarily  attributable  to $46 million of severance and
     related postretirement health and welfare benefits accruals and pension and
     postretirement  curtailment  costs  associated with The Exelon Way and $162
     million of accretion  expense  related to SFAS No. 143.  Accretion  expense
     includes $116 million of accretion of the asset  retirement  obligation and
     $46  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.  For a  further  discussion  of SFAS No.  143,  see Note 2 of the
     Condensed Combined Notes to Consolidated Financial Statements. The increase
     in O&M was also due to $51  million  of  additional  employee  payroll  and
     benefits  costs  and  $68  million  of  additional  expenses  due to  asset
     acquisitions  made  after  the  third  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.  These  increases  were
     partially  offset by $61 million of lower nuclear  refueling  outage costs,
     including $17 million for Generation's  ownership  interest in Salem, which
     is operated by the co-owner,  PSE&G, a one-time executive severance expense





                                      148
<PAGE>

     recorded in 2002 of $19  million,  and an $8 million  reduction in worker's
     compensation expense.

<TABLE>
<CAPTION>
                                                                                        Nine Months Ended September 30,
                                                                                        -------------------------------
                                                                                                   2003            2002
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                                              <C>             <C>
     Nuclear fleet capacity factor (1)                                                            94.5%           92.1%
     Nuclear fleet production cost per MWh (1)                                               $    12.16       $   13.05
     Average purchased power cost for wholesale operations per MWh (2)                       $    45.42       $   43.60
     -------------------------------------------------------------------------------------------------------------------
<FN>
     (1)  Including AmerGen and excluding Salem, which is operated by PSE&G.
     (2)  Including PPAs with AmerGen.
</FN>
</TABLE>

              The  higher  nuclear   capacity   factor  and  decreased   nuclear
     production  costs are primarily due to 66 fewer  planned  refueling  outage
     days,  resulting  in a $44 million  decrease in outage  costs,  in the nine
     months ended September 30, 2003 as compared to the same period in 2002. The
     nine  months  ended  September  30,  2003 and 2002  included  20  unplanned
     outages.

              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,  reduced generation due
     to maintenance and mid-cycle outages. For example, in the second quarter of
     2003,  the Quad  Cities  Unit 1 required a  significant  repair and did not
     operate  above an 85%  capacity  factor  until a root  cause  analysis  was
     completed.  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
     completed  the  analysis  and  returned  the unit to its  normal  operating
     capacity in August 2003.

     Depreciation and Amortization
              Depreciation and amortization  expense  decreased $55 million,  or
     28%,  for the nine months  ended  September  30, 2003  compared to the same
     period in 2002.  The decrease was primarily  attributable  to a $93 million
     reduction  in  decommissioning  expense net of ARC  depreciation,  as these
     costs are included in operating and maintenance  expense after the adoption
     of SFAS No. 143, and a $12 million decrease due to life extensions of asset
     additions  in 2002.  The decrease  was  partially  offset by $39 million of
     additional  depreciation  expense  on capital  additions  placed in service
     after the second  quarter of 2002,  and $13  million of expense  related to
     plant  acquisitions  made after the third  quarter  of 2002.  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 $11 million, or 9%, for the nine
    months  ended  September  30,  2003  compared  to the  same  period  in 2002
    primarily due to a $20 million  decrease in property taxes,  including a $15
    million  reduction to reserves  recorded for exposures  associated with real
    estate taxes.  This decrease was partially  offset by a $17 million increase
    in property taxes related to asset acquisitions made after the third quarter
    of 2002.




                                      149
<PAGE>

     Interest Expense
              Interest  expense  increased  $12  million,  or 24%,  for the nine
     months ended  September 30, 2003  compared to the same period in 2002.  The
     increase  was  primarily  due to $8  million  of  interest  expense  on the
     long-term  debt  assumed  as  a  part  of  the  Exelon  New  England  asset
     acquisition,  $7 million of additional interest expense on the $536 million
     note payable issued to Sithe in November 2002, and a $4 million decrease in
     capitalized  interest.  This  increase is partially  offset by a $3 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  decreased  $29
     million,  or 24%, for the nine months ended  September 30, 2003 compared to
     the same period in 2002. This decrease resulted from a $31 million decrease
     in  Generation's  equity  in  earnings  of  Sithe.  Sithe's  earnings  were
     primarily affected by Generation's  purchase of Exelon New England's assets
     from Sithe in November 2002 and unfavorable mark-to-market losses at Sithe.
     This decrease was partially offset by a $3 million increase in Generation's
     equity in earnings of AmerGen.  AmerGen's  earnings were favorably affected
     in the nine months  ended  September  30, 2003 by  increased  power  sales,
     reduced  outage  costs,  and lower  accretion  expense  resulting  from the
     adoption of SFAS No. 143.  This  favorable  impact was offset by  decreased
     power  sales due to changes in PPAs that  resulted  in lower  prices in the
     summer months.  Conversely, the change in PPAs resulted in higher prices in
     the non-summer months during 2003 as compared to 2002.

     Other, Net
              Other,  net  decreased  $218  million  for the nine  months  ended
     September  30, 2003  compared to the same period in 2002.  This decrease is
     primarily  a result  of $255  million  of  impairment  charges  related  to
     Generation's  equity  investment  in Sithe  due to an  other-than-temporary
     decline in value. This charge was partially offset by $41 million of higher
     net realized  gains and investment  income  related to the  decommissioning
     trust funds.  These net realized  gains and  investment  income were almost
     entirely  offset  with  accretion  expense in 2003,  which is  included  in
     operating and maintenance expense.

     Income Taxes
              The effective  income tax rate was 38.1% for the nine months ended
     September  30,  2003  compared  to 38.7% for the same  period in 2002.  The
     decrease was primarily attributed to the impact of changes in income before
     income taxes as a result of the impairments of  Generation's  investment in
     Sithe and the long-lived assets of EBG.

              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.




                                      150
<PAGE>

     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.

              See  Note  2 of  the  Condensed  Combined  Notes  to  Consolidated
     Financial Statements for further discussion of the adoption of SFAS No. 143
     and SFAS No. 141.

     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 participation in the
     intercompany   money  pool  and/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  distributions to
     Exelon.  Any  future  acquisitions  could  require  external  financing  or
     borrowings or capital contributions from Exelon.

              As part of the  implementation  of The Exelon Way,  Generation has
    identified 317 positions for  elimination by the end of 2004 and anticipates
    identifying   additional   positions  for  elimination  in  2005  and  2006.
    Generation  recorded a charge for cash  severance of $20 million  during the
    third quarter 2003,  which  Generation  anticipates will be paid by December
    31, 2004. Generation anticipates incurring further costs associated with The
    Exelon Way upon  identifying  additional  positions to be eliminated.  These
    costs will be  recorded  in the period in which the costs can be  reasonably
    estimated.

     Cash Flows from Operating Activities

              Cash flows provided by operations were $1,141 million for the nine
     months  ended  September  30,  2003,  compared to $771 million for the same
     period in 2002.  The increase in cash flows from  operating  activities was
     primarily  attributable  to a $530 million  increase in cash flows  derived
     from  working  capital.   Cash  flows  used  in  operating  activities  for
     collateral  were $1 million  as of  September  30,  2003,  compared  to $48
     million for the same period in 2002.  The use of cash for  collateral  will
     depend  upon  future  market  prices for  energy and to the extent  forward
     energy deals are entered into under  agreements with negotiated  collateral
     provisions.  When power prices return to previous levels or when Generation
     delivers the power under its forward  contracts,  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





                                      151
<PAGE>

     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 $772 million for the
     nine months ended  September 30, 2003,  compared to $1,343  million for the
     same  period  in  2002.  The  decrease  in cash  flows  used  in  investing
     activities  during the current  year was  primarily  attributable  to plant
     acquisition  costs of $443 million  during the nine months ended  September
     30, 2002, and $92 million for liquidated  damages received from Raytheon in
     2003 (see Note 9 of the Condensed Combined Notes to Consolidated  Financial
     Statements).

              Generation's   capital   expenditures   for   2003   reflect   the
    construction of three EBG 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 nine
    months  ended  September  30, 2003,  EBG received $92 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  Mystic  8 and 9 and Fore  River.  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 $324 million for the
     nine months ended  September 30, 2003,  compared to cash flows  provided by
     financing  activities  of $387  million  for the same  period in 2002.  The
     decrease in cash flows from  financing  activities  was  primarily due to a
     $526  million  decrease  in cash  receipts  from  affiliates,  $86  million
     increase in distributions  paid to Exelon, the $210 million partial payment
     of the acquisition note payable to Sithe, a reduction in contributions from
     minority  interest  holders of $43 million and a $25 million  reduction  in
     restricted cash during the nine months ended September 30, 2003 compared to
     the same  period  in 2002.  The  decrease  in cash  provided  by  financing
     activities  was  partially  offset by an increase in  borrowings  under the
     revolving  credit facility of $181 million during the current year over the
     same  period  in  2002.  See  Note 12 of the  Condensed  Combined  Notes to
     Consolidated  Financial  Statements for further  discussion of Generation's
     debt financing activities.

     Credit Issues

              Generation meets its short-term liquidity  requirements  primarily
     through  intercompany  borrowings  from  Exelon  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 September 30,
     2003, the sublimit for Generation was zero.





                                      152
<PAGE>

              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  September 30, 2003. At September 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, PECO, Generation and BSC may participate in the
     money pool as lenders and borrowers,  and Exelon  Corporate may participate
     as a lender. Funding of, and borrowings from, the money pool are predicated
     on whether such funding results in mutual economic  benefits to each of 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 nine months ended September 30, 2003, Generation had various borrowings
     under the money pool. The maximum  amount of loans  outstanding at any time
     during the quarter was $344 million.  As of September 30, 2003,  Generation
     owed the money pool $147 million on these loans.  For the nine months ended
     September  30,  2003,  Generation  paid $2 million in interest to the money
     pool.

              EBG has  approximately  $1.1 billion of debt outstanding under the
    EBG  Facility at  September  30,  2003.  The EBG  Facility  was entered into
    primarily to finance the  construction of Mystic 8 and 9 and Fore River. The
    EBG Facility  required that all of the projects achieve 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 were  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.  Project
    Completion  was not  achieved  by July 12,  2003,  resulting  in an event of
    default  under  the  EBG  Facility.  The EBG  Facility  is  non-recourse  to
    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. Mystic 8 and 9 and Fore River are in commercial operation,
    although they have not yet achieved Project Completion.

              As a result of Generation's  continuing evaluation of the projects
     and discussions  with the lenders,  Generation 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,  Generation  expects  to
     continue to provide  administrative and operational  services to EBG in its
     operation of the projects.  Generation informed the lenders of its decision
     to exit and that it will not  provide  additional  funding to the  projects
     beyond its existing contractual obligations.  Generation cannot predict the
     timing of the transition.





                                      153
<PAGE>

              The debt outstanding under the EBG Facility of approximately  $1.1
     billion at September  30, 2003 is reflected  in  Generation'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  of $210  million  relating  to the  $536  million  note,  which  was
     established in connection with the acquisition of Exelon New England.

              On  September  29,  2003,  Generation  replaced  the $550  million
     facility with a new $850 million  revolving credit  facility.  The existing
     $210 million of borrowings under the original  facility remain  outstanding
     under the new credit facility. The note with Sithe has been restructured in
     the third quarter to provide for the  remaining  balance of $326 million to
     be paid in two  installments.  Generation  will be  required  to repay $236
     million of the  principal  on the  earlier of December 1, 2003 or change of
     control,  and the remaining principal balance on the earlier of December 1,
     2004 or change of control.

              Generation's $850 million facility is also expected to provide the
     initial  funding of the  acquisition  of British  Energy's  50% interest in
     AmerGen.

              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.

              As part of the normal  course of business,  Exelon and  Generation
     routinely  enter into  physical or  financially  settled  contracts for the
     purchase  and sale of capacity,  energy,  fuels and  emissions  allowances.
     These  contracts  either  contain  express  provisions or otherwise  permit
     Exelon,  Generation and its  counterparties to demand adequate assurance of
     future  performance  when  there are  reasonable  grounds  for doing so. In
     accordance  with the contracts and  applicable  contracts law, if Exelon or
     Generation  is downgraded  by a credit  rating  agency,  especially if such
     downgrade  is to a level below  investment  grade,  it is  possible  that a
     counterparty  could  attempt  to rely on such a  downgrade  as a basis  for
     making a demand for adequate assurance of future performance.  Depending on
     Exelon or Generation's  net position with a counterparty,  the demand could
     be for the posting of  collateral.  In the absence of  expressly  agreed to
     provisions  that  specify  the  collateral  that  must  be  provided,   the
     obligation  to supply the  collateral  requested  will be a function of the
     facts and circumstances of Exelon or Generation's  situation at the time of
     the demand. If Exelon or Generation can reasonably claim that it is willing
     and  financially  able to perform  its  obligations,  it may be possible to
     successfully  argue  that no  collateral  should  be posted or that only an
     amount  equal  to  two  or  three  months  of  future  payments  should  be
     sufficient.





                                      154
<PAGE>

               Under PUHCA,  Generation  is precluded  from lending or extending
     credit or indemnity to Exelon and can only pay dividends from undistributed
     or current  earnings.  At September 30, 2003,  Generation had undistributed
     earnings of $577 million.

     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  September  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 9 of the  Condensed
          Combined Notes to Consolidated Financial Statements for the commercial
          commitments table 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  to
          purchase the 35.2% interest in Sithe owned by Apollo  Energy,  LLC and
          the 14.9% interest owned by subsidiaries of Marubeni Corporation.  The
          total  purchase  price  under  the call is  based on the  terms of the
          existing  PCA among the parties and is $621  million.  The transfer of
          ownership requires various regulatory  approvals,  including the FERC,
          the state  environmental  agency in New Jersey,  and expiration of the
          Hart Scott Rodino waiting period.  Early termination of the Hart Scott
          Rodino waiting period was granted effective August 22, 2003.

                  Under the terms of the PCA, the purchase  price must be funded
         within  six  months  of the call  notice  being  issued.  Additionally,
         because the Federal Power Act restricts  Generation's ownership of more
         than 50% of a qualifying facility,  the qualifying  facilities owned by
         Sithe must be sold or  restructured  before  closing to preserve  their
         status as qualifying facilities.  See below for information regarding a
         separate  agreement  reached  by  Sithe  to sell  six  U.S.  generating
         facilities,  each a qualifying facility,  and an entity holding Sithe's
         Canadian  assets.  At the closing,  Sithe is expected to  distribute in
         excess of $600 million of available cash to Generation.

                  On August 13, 2003,  Generation  announced  an agreement  with
         entities  controlled by Reservoir,  a private  investment firm, to sell
         50% of Sithe in exchange for $75.8 million in cash. The sale will occur
         after  Generation's  purchase of the remaining 50.1% interest in Sithe.
         The sale  requires  FERC  approval,  a Hart Scott  Rodino  filing and a
         filing with the state regulatory  commission in New York. Both of these
         filings  have been made.  Early  termination  of the Hart Scott  Rodino
         waiting period was granted  September 30, 2003. The sale is expected to
         close in the fourth quarter of 2003.





                                      155
<PAGE>

                  Both Exelon and  Reservoir's  50%  interests  in Sithe will be
         subject  to put and call  options  that  could  result in either  party
         owning 100% of Sithe. While Exelon's intent is to fully divest Sithe by
         the  end of  2004,  the  timing  of the put and  call  options  vary by
         acquirer and can extend  through March 2006. The pricing of the put and
         call  options is dependent  on numerous  factors such as the  acquirer,
         date of acquisition and assets owned by Sithe at the time of exercise.

                  In a separate transaction, Sithe has entered into an agreement
         with Reservoir to sell entities holding six U.S. generating facilities,
         each a qualifying facility under the Public Utility Regulatory Policies
         Act,  and an entity  holding  Sithe's  Canadian  assets in exchange for
         $46.2 million ($26.2 million in cash and a $20 million  two-year note).
         The  sale  requires  approvals  from  Sithe's  board of  directors  and
         shareholders  and  regulatory  filings in New Jersey and  Canada.  Both
         these filing have been made.  The sale is also expected to close in the
         fourth  quarter  of 2003.  This sale is not  contingent  on the sale of
         Generation's 50% interest in Sithe to Reservoir.

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

     o    On August 14, 2003,  Generation  received a letter from the Department
          of Energy  (DOE)  demanding  repayment  of $40  million of  previously
          received credits from the Nuclear Waste Fund. The letter also demanded
          $1.5 million of accrued  interest  expense.  Although a new settlement
          would  offset  Generation's   payments,   Generation  nonetheless  has
          reserved its 50% ownership share of these amounts.  Because Generation
          expenses the casks and  capitalizes  the  permanent  components of its
          spent fuel storage facilities,  these reserves increased  Generation's
          operating and maintenance  expense  approximately  $11 million and its
          capital  base  approximately  $9 million  during the third  quarter of
          2003.  The  remainder  of the recorded  obligation  to the DOE will be
          recovered  from the  co-owner  of the  facility.  See Note 9 - Nuclear
          Decommissioning  and Spent Nuclear Fuel Storage in  Generation's  2002
          Form 10-K for additional information regarding this matter.

     o    Under the  Price-Anderson  Act, all nuclear  reactor  licensees can be
          assessed a maximum charge per reactor per incident.  Effective  August
          20, 2003, the maximum assessment for all nuclear operators per reactor
          per incident (including a 5% surcharge)  increased from $89 million to
          $101 million. The maximum payable per reactor per incident per year of
          $10 million is unchanged.  The change in the maximum assessment is the
          result of an inflation adjustment, required by the Price-Anderson Act.
          Based on the increase of the maximum assessment,  Generation's nuclear
          insurance guarantee of AmerGen's plants increased from $134 million to
          $151 million.





                                      156
<PAGE>

     o    On October 10, 2003,  Exelon executed an agreement to purchase British
          Energy's 50% interest in AmerGen for $276.5  million.  The transaction
          is expected  to close in the first half of 2004.  The  purchase  price
          matched the offer by FPL Energy, which announced on September 11, 2003
          that it intended to buy British  Energy's share of AmerGen.  Under the
          AmerGen limited liability  company operating  agreement between Exelon
          and British  Energy,  either can exercise a right of first  refusal by
          matching  any bona  fide  third-party  offer  agreed  to by the  other
          member.  See  Note 4 of the  Condensed  Combined  Notes  to  Financial
          Statements for additional information regarding AmerGen.

              As  discussed  in  Note  2 of  the  Condensed  Combined  Notes  to
     Consolidated   Financial   Statements,   it  is  reasonably  possible  that
     Generation  will  consolidate  Sithe and  AmerGen as of  December  31, 2003
     pursuant to FIN No. 46,  "Consolidation of Variable Interest Entities." See
     Note 4 of the Condensed Combined Notes to Consolidated Financial Statements
     for further discussion of Generation's investments in Sithe and AmerGen.


     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  94%  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.




                                      157
<PAGE>

              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 $6
     million  decrease in net income,  or  approximately  $0.02 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.

     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.



                                      158
<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 nine months ended  September  30, 2003.  Normal
     operations  and hedging  activities  represent the marketing of electricity
     available from  Generation's  owned or contracted  generation sold into the
     wholesale market,  including to ComEd and PECO to serve their retail loads.
     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 September 30, 2003
                                                                  -----------------------------------------------------
                                                                   Normal Operations and      Proprietary
                                                                   Hedging Activities (a)         Trading         Total
     ------------------------------------------------------------------------------------------------------------------
     Mark-to-market activities:
     --------------------------
<S>                                                                             <C>               <C>          <C>
     Unrealized mark-to-market gain/(loss)
        Origination unrealized gain/(loss) at inception                       $       --       $       --      $     --
        Changes in fair value prior to settlements                                    47                1            48
        Changes in valuation techniques and assumptions                               --               --            --
        Reclassification to realized at settlement of contracts                      (65)              (1)          (66)
     ------------------------------------------------------------------------------------------------------------------
        Total change in unrealized fair value                                        (18)              --           (18)
     Realized net settlement of transactions subject to mark-to-market                65                1            66
     ------------------------------------------------------------------------------------------------------------------
     Total mark-to-market activities gross margin                             $       47       $        1      $     48
     ------------------------------------------------------------------------------------------------------------------

     Accrual activities:
     -------------------
     Accrual activities revenue                                               $    1,642       $       --      $  1,642
     Hedge gains/(losses) reclassified from OCI                                      710               --           710
     ------------------------------------------------------------------------------------------------------------------
        Total revenue - accrual activities                                         2,352               --         2,352
     ------------------------------------------------------------------------------------------------------------------
     Purchased power and fuel                                                        765               --           765
     Hedges of purchased power and fuel reclassified from OCI                        787               --           787
     ------------------------------------------------------------------------------------------------------------------
        Total purchased power and fuel                                             1,552               --         1,552
     ------------------------------------------------------------------------------------------------------------------
        Total accrual activities gross margin                                        800               --           800
     ------------------------------------------------------------------------------------------------------------------
     Total gross margin                                                      $       847       $         1    $     848 (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>






                                      159
<PAGE>

<TABLE>
<CAPTION>
                                                                                   Nine Months Ended September 30, 2003
                                                             ----------------------------------------------------------
                                                                   Normal Operations and       Proprietary
                                                                      Hedging Activities (a)       Trading        Total
     ------------------------------------------------------------------------------------------------------------------
     Mark-to-market activities:
     --------------------------
<S>                                                                                 <C>                <C>         <C>
     Unrealized mark-to-market gain/(loss)
        Origination unrealized gain/(loss) at inception                       $       --       $       --      $     --
        Changes in fair value prior to settlements                                   182               (1)          181
        Changes in valuation techniques and assumptions                               --               --            --
        Reclassification to realized at settlement of contracts                     (199)              (3)         (202)
     ------------------------------------------------------------------------------------------------------------------
        Total change in unrealized fair value                                        (17)              (4)          (21)
     Realized net settlement of transactions subject to mark-to-market               199                3           202
     ------------------------------------------------------------------------------------------------------------------
     Total mark-to-market activities gross margin                             $      182       $       (1)     $    181
     ------------------------------------------------------------------------------------------------------------------

     Accrual activities:
     -------------------
     Accrual activities revenue                                               $    4,099       $       --      $  4,099
     Hedge gains/(losses) reclassified from OCI                                    1,724               --         1,724
     ------------------------------------------------------------------------------------------------------------------
        Total revenue - accrual activities                                         5,823               --         5,823
     ------------------------------------------------------------------------------------------------------------------
     Purchased power and fuel                                                      1,745               --         1,745
     Hedges of purchased power and fuel reclassified from OCI                      1,995               --         1,995
     ------------------------------------------------------------------------------------------------------------------
        Total purchased power and fuel                                             3,740               --         3,740
     ------------------------------------------------------------------------------------------------------------------
        Total accrual activities gross margin                                      2,083               --         2,083
     ------------------------------------------------------------------------------------------------------------------
     Total gross margin                                                      $     2,265       $       (1)    $   2,264 (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>

              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 September 30, 2003. It indicates the drivers  behind  changes in
     the balance  sheet  amounts.  This table  incorporates  the  mark-to-market
     activities  that are 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 September 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 nine months ended September 30, 2003
          of contracts recorded in earnings                                                  182           (1)      181
     Reclassification to realized at settlement of contracts recorded in earnings           (199)          (3)     (202)
     Reclassification to realized at settlement from OCI                                     271           --       271
     Effective portion of changes in fair value - recorded in OCI                           (205)          --      (205)
     Purchase/sale of existing contracts or portfolios subject to mark-to-market              --           --        --
     ------------------------------------------------------------------------------------------------------------------
     Total mark-to-market energy contract net assets (liabilities)
         at September 30, 2003                                                         $    (119)   $       1    $ (118)
     ==================================================================================================================
</TABLE>




                                      160
<PAGE>

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

<TABLE>
<CAPTION>
                                                                        Normal Operations and   Proprietary
                                                                           Hedging Activities       Trading       Total
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                                <C>            <C>         <C>
     Current assets                                                                $      204     $       1   $     205
     Noncurrent assets                                                                     79            --          79
     ------------------------------------------------------------------------------------------------------------------
        Total mark-to-market energy contract assets                                       283             1         284
     ------------------------------------------------------------------------------------------------------------------

     Current liabilities                                                                (301)            --        (301)
     Noncurrent liabilities                                                             (101)            --        (101)
     ------------------------------------------------------------------------------------------------------------------
        Total mark-to-market energy contract liabilities                                (402)            --        (402)
     ------------------------------------------------------------------------------------------------------------------
     Total mark-to-market energy contract net assets (liabilities)                 $    (119)     $      1    $    (118)
     ==================================================================================================================
</TABLE>

              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  September  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.









                                      161
<PAGE>

              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                  $(6)  $  (98)   $ (10)  $  (6)  $  --  $   --     $  (120)
     ------------------------------------------------------------------------------------------------------------------------
       Total                                                       $(6)  $  (98)   $ (10)  $  (6)  $  --  $   --     $  (120)
     ------------------------------------------------------------------------------------------------------------------------

     Normal Operations, other derivative contracts (2):
        Actively quoted prices                                    $ --   $    2    $  --   $  --   $  --  $   --     $     2
        Prices provided by other external sources                    4       14        5       4      --      --          27
        Prices based on model or other valuation methods             4      (17)      (3)     (9)     (3)     --         (28)
     ------------------------------------------------------------------------------------------------------------------------
       Total                                                       $ 8   $   (1)   $   2   $  (5)  $  (3) $   --     $     1
     ------------------------------------------------------------------------------------------------------------------------

     Proprietary Trading, other derivative contracts (3):
        Actively quoted prices                                     $(2)  $    3    $  --   $  --   $  --  $   --     $     1
        Prices provided by other external sources                    1       (4)       1      --      --      --          (2)
        Prices based on model or other valuation methods             1        1       --      --      --      --           2
     ------------------------------------------------------------------------------------------------------------------------
       Total                                                       $--   $   --    $   1   $  --   $  --  $   --     $     1
     ========================================================================================================================
     Average tenor of proprietary trading portfolio (4)                                                            1.75 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>









                                      162
<PAGE>

              The table below  provides  details of  effective  cash flow hedges
     under SFAS No. 133 included in the balance  sheet as of September 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 nine  months  ended
     September 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 derivative loss at January 1, 2003               $       (114)      $           (5)     $     (119)
     Changes in fair value                                                    (124)                 (11)           (135)
     Reclassifications from OCI to net income                                  165                    --            165
     -------------------------------------------------------------------------------------------------------------------
     Accumulated OCI derivative loss
        at September 30, 2003                                         $        (73)      $          (16)      $     (89)
     ===================================================================================================================
<FN>
     (1) Includes interest rate hedges at Generation.
</FN>
</TABLE>

              Generation  uses a 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
     liquidate the portfolio.  A two-tailed test considers  potential  upside in
     the  portfolio  in addition  to the  potential  downside  in the  portfolio





                                      163
<PAGE>

     considered in the one-tailed test. The following table provides the VaR for
     all proprietary trading positions of Generation as of September 30, 2003.

<TABLE>
<CAPTION>
                                                                                                            Proprietary
                                                                                                            Trading VaR
     -------------------------------------------------------------------------------------------------------------------
<S>                                                                                                          <C>
     95% Confidence Level, One-Day Holding Period, One-Tailed
        Period end                                                                                           $     0.1
        Average for the period                                                                                     0.1
        High                                                                                                       0.2
        Low                                                                                                        0.0

     95% Confidence Level, Ten-Day Holding Period, Two-Tailed
        Period end                                                                                           $     0.2
        Average for the period                                                                                     0.3
        High                                                                                                       0.6
        Low                                                                                                        0.1

     99% Confidence Level, One-Day Holding Period, Two-Tailed
        Period end                                                                                           $     0.1
        Average for the period                                                                                     0.1
        High                                                                                                       0.2
        Low                                                                                                        0.0
     -------------------------------------------------------------------------------------------------------------------
</TABLE>

     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.







                                      164
<PAGE>

              The following  tables provide  information on Generation's  credit
     exposure,  net of  collateral,  as of  September  30,  2003.  They  further
     delineate  that  exposure by the credit  rating of the  counterparties  and
     provide  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 tables  below do 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                                      $    208     $  --    $   208                2          $       81
     Split rating                                                --        --         --               --                  --
     Non-investment grade                                        14         6          8               --                  --
     No external ratings
        Internally rated - investment grade                      26         4         22                3                  10
        Internally rated - non-investment grade                  11         5          6                1                  11
     --------------------------------------------------------------------------------------------------------------------------
     Total                                                 $    259     $  15   $    244               6           $      102
     ==========================================================================================================================

</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                                              $     194      $   14       $     --      $      208
     Split rating                                                         --          --             --              --
     Non-investment grade                                                 14          --             --              14
     No external ratings
        Internally rated - investment grade                               25           1             --              26
        Internally rated - non-investment grade                           11          --             --              11
     -------------------------------------------------------------------------------------------------------------------
     Total                                                         $     244      $   15       $     --      $      259
     ===================================================================================================================
</TABLE>

              Generation  is  a   counterparty   to  Dynegy  in  various  energy
     transactions.  The credit ratings of Dynegy are considered below investment
     grade by two credit rating agencies.  Generation 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 September 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 provisions 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 $16 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.





                                      165
<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.

              ComEd and  Generation  are  parties to various  transactions  with
     Midwest   Generation.   Midwest   Generation's  credit  ratings  have  been
     downgraded by certain  credit rating  agencies.  Furthermore,  the June 30,
     2003 Form 10-Q filed by Edison Mission Energy (EME), an intermediate parent
     company of Edison Mission Midwest  Holdings (EMMH) and Midwest  Generation,
     indicates that EMMH is not expected to have  sufficient  cash to repay $911
     million of debt when it matures on December  11,  2003; a failure to repay,
     extend,  or refinance the EMMH obligation  would likely result in a default
     under the  senior  secured  notes and term loan of Mission  Energy  Holding
     Company, EME's parent company; and these events could make it necessary for
     EME to file a petition for  reorganization  under  Chapter 11 of the United
     States  Bankruptcy  Code.  Reorganization  under  Chapter  11 of the United
     States Bankruptcy Code does not assure non-performance under all contracts;
     however,   the  reorganization   would  increase  the  possibility  of  the
     obligations described in the following two paragraphs reverting to ComEd or
     Generation.

              In  connection  with  ComEd's  sale in  December  1999  of  fossil
     generating  assets to  Midwest  Generation,  ComEd  entered  into an agency
     agreement  with  EMMH  and  EME  whereby  EMMH  assumed  the  benefits  and
     liabilities of a long-term coal purchase  contract and a railcar lease. EME
     guaranteed  EMMH's  performance.  EMMH did not become a direct party to the
     obligations,  and  ComEd  remained  obligated  and  was  not  released.  In
     connection with the Merger and subsequent restructuring, Generation assumed
     any contingent  obligation on these  contracts from ComEd.  In the event of
     EMMH and EME's non-performance under the coal purchase contract, Generation
     would be required to fulfill the purchase  commitments  that 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 minimum purchase obligation for
     the  contract  years 2003 to 2012 are  estimated  to be  approximately  $81
     million (the net present value of the obligation  approximates $51 million)
     related to this  agreement.  The railcar lease covers  approximately  1,400
     coal  transport  railcars  through  2014.  In the  event of EMMH and  EME's
     non-performance  under the railcar lease,  Generation  would be required to
     fulfill the lease payments that extend  through 2014.  The remaining  lease
     payments for the railcars approximate $65 million (the net present value of
     the obligation approximates $38 million).  However, based on current prices
     for railcars in these particular  markets,  Generation believes it would be
     able to effectively  sublease the railcars  without  incurring any exposure
     related to this obligation.

              Generation  and ComEd  have  entered  into other  agreements  with
     Midwest  Generation and have other related  exposures.  In connection  with
     ComEd's  fossil  generating  asset  sale  to  Midwest  Generation,  Midwest
     Generation  and EME agreed to  indemnify  ComEd for  various  environmental
     exposures  or  penalties.  Generation  assumed any  contingent  obligations
     relating to generation-related  environmental issues of ComEd in connection
     with the Merger and  subsequent  restructuring.  Exelon  cannot  reasonably
     estimate the possible environmental exposures or penalties that could arise
     if Midwest  Generation  or EME do not honor their  indemnity to ComEd or if
     the  indemnity  is  discharged  in  bankruptcy.   Midwest  Generation  also
     indemnified   Generation   and   ComEd   for   approximately   50%  of  any
     post-acquisition  asbestos  claims  relating  to the plants sold to Midwest
     Generation. Generation assumed any contingent obligations of ComEd relating
     to these  asbestos  claims in  connection  with the Merger  and  subsequent
     restructuring.  The bankruptcy of or  non-performance of Midwest Generation
     of its obligations to Generation and ComEd for asbestos claims could result
     in contingent  obligations to Generation and ComEd of up to an estimated $5
     million.  In addition,  ComEd is exposed to risks  associated with accounts
     receivable from  transmission and station power services  provided by ComEd
     to Midwest  Generation.  The  bankruptcy of or  non-performance  of Midwest
     Generation of its obligations to ComEd for  transmission  and station power
     services  provided by ComEd could result in ComEd  recording a write-off of
     up to an estimated $3 million.

              Generation accounts for certain derivative  financial  instruments
     under the normal  purchases and normal sales  exemption of SFAS No. 133. As
     of September 30, 2003, Generation is a party to forward energy purchase and
     sale  contracts  with Midwest  Generation,  which are accounted for in that
     manner and, as such,  are not  marked-to-market.  If Generation  determines
     that the  possibility  of  non-performance  by Midwest  Generation on these
     contracts becomes more than remote,  these contracts will be required to be
     marked-to-market  through earnings,  which would be expected to result in a
     charge to Exelon and  Generation's  results of  operations  and such charge
     could be material.

              As part of the normal  course of business,  Exelon and  Generation
     routinely  enter into  physical or  financially  settled  contracts for the
     purchase  and sale of capacity,  energy,  fuels and  emissions  allowances.
     These  contracts  either  contain  express  provisions or otherwise  permit
     Exelon,  Generation and its  counterparties to demand adequate assurance of
     future  performance  when  there are  reasonable  grounds  for doing so. In
     accordance  with the contracts and  applicable  contracts law, if Exelon or
     Generation  is downgraded  by a credit  rating  agency,  especially if such
     downgrade  is to a level below  investment  grade,  it is  possible  that a
     counterparty  could  attempt  to rely on such a  downgrade  as a basis  for
     making a demand for adequate assurance of future performance.  Depending on
     Exelon or Generation's  net position with a counterparty,  the demand could
     be for the posting of  collateral.  In the absence of  expressly  agreed to
     provisions  that  specify  the  collateral  that  must  be  provided,   the
     obligation  to supply the  collateral  requested  will be a function of the
     facts and circumstances of Exelon or Generation's  situation at the time of
     the demand. If Exelon or Generation can reasonably claim that it is willing
     and  financially  able to perform  its  obligations,  it may be possible to
     successfully  argue  that no  collateral  should  be posted or that only an
     amount  equal  to  two  or  three  months  of  future  payments  should  be
     sufficient.

     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





                                      166
<PAGE>

     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
     September  30,  2003,  ComEd has  settled  all of its  interest  rate swaps
     designated as cash flow hedges.

              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
     September 30, 2003,  these  interest  rate swaps,  designated as fair value
     hedges,  had an  aggregate  fair market  value of $39 million  based on the
     present value difference between the contract and market rates at September
     30, 2003. If these derivative  instruments had been terminated at September
     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 September  30, 2003 is estimated to be
     $45 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 September  30, 2003 is estimated to be
     $33 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 September 30, 2003,
     these  interest rate swaps had an aggregate  fair market value  exposure of
     $11 million based on the present value difference  between the contract and
     market rates at September 30, 2003.  If these  derivative  instruments  had
     been terminated at September 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  September  30,  2003  is  estimated  to be  $12  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  September  30,  2003  is  estimated  to be  $10  million  in the
     counterparties favor.




                                      167
<PAGE>

              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.  As of
     September  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 nine months ended September 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 September  30, 2003,  EBG had entered
     into interest rate swap agreements that have effectively fixed the interest
     rate on  $861  million  of  notional  principal,  or  approximately  80% of
     borrowings  outstanding  under the EBG Facility at September 30, 2003.  The
     fair market value exposure of these swaps,  designated as cash flow hedges,
     is $91 million.  If these  derivative  instruments  had been  terminated at
     September 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  September  30,  2003 is
     estimated to be $104 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  September  30,  2003 is
     estimated to be $78 million in the counterparties favor.

              In 2003,  Generation entered into  forward-starting  interest rate
     swaps in the  aggregate  amount of $400  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 September
     30, 2003, these interest rate swaps, designated as cash flow hedges, had an
     aggregate  fair market value  exposure of less than $1 million based on the
     present  value of the  difference  between the contract and market rates at
     September 30, 2003. If these derivative  instruments had been terminated at
     September 30, 2003,  this estimated fair value  represents the amount to be
     paid by Generation 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  September  30,  2003 is
     estimated to be $17 million in the counterparties favor.





                                      168
<PAGE>

              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 September  30, 2003 is estimated to be
     $16 million in Generation's favor.

     Equity Price Risk
     Generation
              Generation  maintains trust funds, as required by the NRC, to fund
     certain costs of  decommissioning  its nuclear plants.  As of September 30,
     2003,   decommissioning   trust  funds  are  reflected  at  fair  value  on
     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
     $212 million reduction in the fair value of the trust assets.

     ITEM 4. CONTROLS AND PROCEDURES

     Exelon
              During the third 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.

              Accordingly,  as of September 30, 2003, these officers  (principal
     executive officer and principal  financial officer) concluded that Exelon's
     disclosure  controls and  procedures  were  effective to  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.




                                      169
<PAGE>

     ComEd
              During the third 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.

              Accordingly,  as of September 30, 2003, these officers  (principal
     executive officer and principal  financial  officer) concluded that ComEd's
     disclosure  controls and  procedures  were  effective to  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.

     PECO
              During the third quarter of 2003, PECO's management, including the
     principal  executive  officer and principal  financial  officer,  evaluated
     PECO's  disclosure  controls  and  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.

              Accordingly,  as of September 30, 2003, these officers  (principal
     executive officer and principal  financial  officer)  concluded that PECO's
     disclosure  controls and  procedures  were  effective to  accomplish  their





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<PAGE>

     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.

     Generation
              During  the  third  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  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.

              Accordingly,  as of September 30, 2003, these officers  (principal
     executive  officer  and  principal   financial   officer)   concluded  that
     Generation's   disclosure   controls  and  procedures   were  effective  to
     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.



                                      171
<PAGE>


     PART II - OTHER INFORMATION

     ITEM 1.      LEGAL PROCEEDINGS

     ComEd
              As  previously  reported  in the 2002  Form 10-K and the June 2003
     Form  10-Q,  three of ComEd's  wholesale  municipal  customers  had filed a
     complaint  and request for refund with the FERC  alleging that ComEd failed
     to  properly  adjust  its rates  pursuant  to the  terms of the  respective
     electric service contracts.  In July 2003 ComEd and the municipal customers
     executed a  settlement  agreement  ending the  litigation.  Pursuant to the
     settlement,  ComEd paid  approximately  $3 million,  in total, to the three
     municipalities.

     Generation
              As  previously  reported  in the 2002  Form 10-K and the June 2003
     Form 10-Q,  Generation  and  Raytheon  are  involved in various  litigation
     matters in connection  with EBG. On August 29, 2003,  Raytheon  filed a new
     action against two subsidiaries of EBG (Project  Companies) and BNP Paribas
     in the  Superior  Court  of the  Commonwealth  of  Massachusetts.  Raytheon
     alleged  that the  Project  Companies  and BNP  Paribas  failed to  provide
     adequate  assurance that Raytheon  would be paid the remaining  amounts due
     under the Fore River and Mystic  construction  contracts.  Raytheon sought:
     (1) an  injunction  preventing  the Project  Companies and BNP Paribas from
     drawing upon certain letters of credit guaranteeing Raytheon's performance;
     (2) the right to terminate  the  construction  contracts;  and (3) an order
     allowing  Raytheon  to  seize  project  funds  totaling  approximately  $40
     million.  Raytheon subsequently  dismissed BNP Paribas from the litigation.
     On October 9, 2003,  the court issued a preliminary  injunction  preserving
     the status quo and preventing  the Project  Companies from drawing upon the
     letters of credit until such time as the court decides  Raytheon's  pending
     motion  for  partial  summary  judgment.  The court has heard  argument  on
     Raytheon's  motion for partial  summary  judgment but has not announced any
     decision.

                On October 2, 2003,  Mitsubishi Heavy Industries,  LTD (MHI) and
     Mitsubishi  Heavy Industries of America (MHIA) filed a New York state court
     action  against  Exelon  Mystic  Development,  LLC and  Exelon  Fore  River
     Development,   LLC  seeking  to  enjoin  these  indirect   subsidiaries  of
     Generation  from drawing upon letters of credit  posted to guarantee  MHI's
     performance under certain gas turbine contracts. MHI and MHIA also seek $34
     million  from these  entities in  connection  with work  performed on these
     contracts. Generation believes that Exelon Mystic's and Exelon Fore River's
     contracts with MHI and MHIA have been assigned to Raytheon  Corporation and
     that the claims against the Exelon entities are without merit.


     ITEM 3.      DEFAULTS UPON SENIOR SECURITIES

     Generation
              EBG has  approximately  $1.1 billion of debt outstanding under the
    EBG Facility.  The EBG Facility,  which is non-recourse  to Generation,  was
    entered  into  primarily to finance the  construction  of Mystic 8 and 9 and
    Fore River and required that all of the projects achieve Project  Completion
    by June 12, 2003. EBG negotiated an extension of the required




                                      172
<PAGE>

     completion  date to July 11, 2003.  Project  Completion was not achieved by
     July 12,  2003,  resulting in an event of default  under the EBG  Facility.
     Although  the  generating  units  are  in  commercial  operation,   Project
     Completion  has not been  achieved to date.  The event of default under the
     EBG Facility  does not  constitute an event of default under any other debt
     instruments of Exelon or its subsidiaries. EBG does not know which, if any,
     remedies the lenders will exercise.

     ITEM 5.      OTHER INFORMATION

     ComEd
              As previously  reported in the 2002 Form 10-K,  in July 2002,  the
     FERC conditionally approved ComEd's decision to join PJM. On April 1, 2003,
     ComEd  received  approval  from the FERC to  transfer  control  of  ComEd's
     transmission  assets to PJM.  The 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. On September 11, 2003, the
     August 14, 2003  blackout  caused PJM to delay  ComEd's  integration  until
     spring  of 2004.  PJM  wants to  integrate  any  lessons  learned  from the
     blackout probes into ComEd's transition plan.

              On August 21, 2003,  ComEd set a new record for highest daily peak
     load experienced to date of 22,054 MWs.

     PECO
              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 and subsequent  auction in September 2003,
     an  aggregate  of 267,000  residential  customers  will be  transferred  to
     alternative   electric  generation  suppliers  during  December  2003.  Any
     customer transferred has the right to return to PECO at any time.






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<PAGE>

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits:


        10.1 -  Retirement and Separation  between  Exelon  Corporation,  PECO
                Energy  Company  and  Kenneth G.  Lawrence,  dated as of May 11,
                2003. Filed on behalf of PECO.

        10.2  - Purchase  and Sale  Agreement  dated as of October  10,  2003
                between  British Energy  Investment  Ltd. and Exelon  Generation
                Company,  LLC  relating to the sale and  purchase of 100% of the
                shares of British  Energy US  Holdings  Inc.  Filed on behalf of
                Exelon and Generation.


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 September 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 September 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
--------------------------------------------------------------------------------

(b) Reports on Form 8-K:

         Exelon, ComEd, PECO and/or Generation filed Current Reports on Form 8-K
     during the three months ended  September  30, 2003  regarding the following
     items:

Date of Earliest
Event Reported            Description of Item Reported
--------------------------------------------------------------------------------
July 3, 2003              "ITEM 5. OTHER EVENTS" filed for Exelon and Generation
                          regarding  the fact that EBG did not  anticipate  that
                          the  construction of the Mystic 8 and 9 and Fore River
                          generating  stations would achieve Project  Completion
                          as defined in EBG's credit facility by July 11, 2003.





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<PAGE>

July 29, 2003             "ITEM 5. OTHER EVENTS" filed for Exelon and Generation
                          announcing  that  Exelon  commenced  the process of an
                          orderly transition out of the ownership of EBG and the
                          projects.

August 6, 2003            "ITEM 5. OTHER EVENTS" filed for Exelon,  ComEd,  PECO
                          and  Generation  reaffirming  Exelon's  2003  earnings
                          guidance and announcing  workforce  reductions related
                          to The Exelon Way.

August 13, 2003           "ITEM 5. OTHER EVENTS" filed for Exelon and Generation
                          regarding  a  note  to  Exelon's  financial  community
                          announcing an agreement  with  entities  controlled by
                          Reservoir  to sell 50% of Sithe,  after  closing  on a
                          call transaction  announced in May 2003. In a separate
                          transaction,  Sithe has entered into an agreement with
                          Resevoir to sell entities holding six U.S.  generating
                          facilities  and an  entity  holding  Sithe's  Canadian
                          assets.

August 25, 2003           "ITEM 5.  OTHER  EVENTS"  filed  for  ComEd  regarding
                          ComEd's sale of $250 million of First Mortgage  Bonds.
                          "ITEM 7. FINANCIAL  STATEMENTS AND EXHIBITS" including
                          exhibits  to  ComEd's  Form  S-3,   Registration   No.
                          333-99363.

August 29, 2003           "ITEM 5. OTHER EVENTS" filed for Exelon and Generation
                          regarding  the fact that the period  during  which the
                          lenders were  precluded  from  exercising any remedies
                          resulting  from the  failure  of the EBG  projects  to
                          achieve  Project  Completion  had expired.  Exelon was
                          continuing  discussions with the lenders regarding the
                          orderly   transition  of  the  projects.   Exelon  has
                          informed the lenders that  Generation will not provide
                          additional funding to the projects beyond its existing
                          contractual obligations.

September 12, 2003        "ITEM 5.  OTHER  EVENTS"  filed for  Exelon  and ComEd
                          regarding a filing with the Federal Energy  Regulatory
                          Commission  to  seek  an  adjustment  in  transmission
                          rates.   The  exhibit   includes  the  press   release
                          announcing the filing.

September 24, 2003        "ITEM 5. OTHER  EVENTS"  filed for  Exelon  announcing
                          that it had finalized the sale of InfraSource, Inc.

September 26, 2003        "ITEM 5.  OTHER  EVENTS"  filed for  Exelon  and ComEd
                          announcing that Exelon is exploring the possibility of
                          acquiring Illinois Power Company from Dynegy Inc.

--------------------------------------------------------------------------------




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<PAGE>


                                   SIGNATURES

--------------------------------------------------------------------------------


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

                               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)

     October 29, 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                    /s/ Frank M. Clark
     ---------------------                    ------------------
     DUANE M. DESPARTE                        FRANK M. CLARK
     Vice President and Controller,           President, ComEd
     Exelon Energy Delivery
     (Principal Accounting Officer)

     October 29, 2003








                                      176

--------------------------------------------------------------------------------

<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                    /s/ Denis P. O'Brien
     ---------------------                    --------------------
     DUANE M. DESPARTE                        DENIS P. O'BRIEN
     Vice President and Controller,           President, PECO
     Exelon Energy Delivery
     (Principal Accounting Officer)

     October 29, 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)

     October 29, 2003








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<PAGE>