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

RESULTS OF OPERATIONS

Three Months Ended March 31, 2003 Compared To Three Months Ended March 31, 2002

Net Income and Earnings Per Share

Exelon's net income for the three months ended March 31, 2003 increased $353 million, compared to the same period in 2002. Diluted earnings per common share on the same basis increased $1.09 per share. Net income for the three months ended March 31, 2003 reflects $112 million of income for the cumulative effect of a change in accounting principle as a result of the adoption of Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) SFAS No. 143, "Asset Retirement Obligations" (SFAS No. 143), while net income for the three months ended March 31, 2002 reflects a $230 million charge for the cumulative effect of a change in accounting principle as a result of 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 adoption of SFAS No. 143 and SFAS No. 142.

Income Before Cumulative Effect of Changes in Accounting Principles for the three months ended March 31, 2003 increased $11 million, or 5%, compared to the same period in 2002. Diluted earnings per common share on the same basis increased $0.04 per share, or 5%. The increase in income before cumulative effect of changes in accounting principles reflects an overall increase in revenue net fuel due to colder weather conditions and increased recoveries of competitive transition charges (CTCs), reduced nuclear refueling outage costs, reduced depreciation expense resulting from lower depreciation rates at Energy Delivery, and decreased interest expense. This increase was partially offset by the impairment of an investment in Sithe Energies, Inc. held by Generation, a one-time charge at Energy Delivery (see Note 4 of the Condensed Combined Notes to Consolidated Financial Statements) and increased operating and maintenance expenses at Generation due to plant acquisitions after the first quarter of 2002.

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 March 31, 2003 to operating results and other statistical information for the same period in 2002. These results reflect intercompany transactions, which are eliminated in our consolidated financial statements.

Corporate provides 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, Corporate costs reflect costs for strategic long-term planning, certain governmental affairs, and interest costs and income from various investment and financing activities.

                                                    Three Months Ended March 31,
                                                    ---------------------------
                                                          2003              2002         Variance          % Change
-------------------------------------------------------------------------------------------------------------------
Energy Delivery                                      $     325         $     215         $    110           51.2%
Generation                                                 (52)               66             (118)        (178.8%)
Enterprises                                                (17)              (28)              11          (39.3%)
Corporate                                                   (7)              (15)               8          (53.3%)
-------------------------------------------------------------------------------------------------
Total                                                $     249         $     238         $     11            4.6%
=================================================================================================

Net Income (Loss) by Business Segment

                                                    Three Months Ended March 31,
                                                    ---------------------------
                                                          2003              2002         Variance          % Change
-------------------------------------------------------------------------------------------------------------------
Energy Delivery                                      $     330         $     215         $    115           53.5%
Generation                                                  56                79              (23)         (29.1%)
Enterprises                                                (18)             (271)             253          (93.4%)
Corporate                                                   (7)              (15)               8          (53.3%)
-------------------------------------------------------------------------------------------------
Total                                                $     361         $       8         $    353              n.m.
=================================================================================================

n.m. - not meaningful

Results of Operations - Energy Delivery
                                                            Three Months Ended March 31,
                                                            ----------------------------
 Energy Delivery                                                       2003         2002     Variance      % Change
-------------------------------------------------------------------------------------------------------------------
Operating Revenues                                                $   2,642     $  2,335       $  307        13.1%
Revenue, net of Purchased Power & Fuel Expense                        1,451        1,311          140        10.7%
Operating Income                                                        694          559          135        24.2%
Income Before Income Taxes and Cumulative Effect of a
   Change in Accounting Principle                                       517          341          176        51.6%
Net Income Before Cumulative Effect of a Change in
   Accounting Principle                                                 325          215          110        51.2%
Net Income                                                              330          215          115        53.5%
-------------------------------------------------------------------------------------------------------------------

The changes in Energy Delivery's revenue, net of purchased power and fuel expense, for the three months ended March 31, 2003 compared to the same period in 2002, included the following:

o changes in customer rates resulting in an $82 million increase,

o increases in weather normalized volumes of $31 million as a result of increases in the number of customers and additional average usage per customer, primarily residential customers,

o favorable weather impacts of $78 million, primarily the results of colder winter weather,

o net unfavorable changes due to customer choice of $8 million, including ComEd's customers electing to purchase energy from alternative energy suppliers or electing ComEd's Power Purchase Option (PPO), under which non-residential customers can purchase power from ComEd at a market-based rate, partially offset by customers returning to PECO as their energy supplier,

o pricing changes related to ComEd's PPA with Generation resulting in a $17 million decrease,

o increase of $16 million in purchases under the ComEd PPA with Generation related to decommissioning collections associated with the adoption of SFAS No. 143 in 2003, which were not recorded in purchased power in 2002, (see Note 2 of the Condensed Combined Notes to Consolidated Financial Statements), and

o higher PJM ancillary purchased power charges resulted in a decrease of $17 million.

The changes in operating income, other than changes in revenue net of purchased power and fuel expense, for the three months ended March 31, 2003 compared to the same period in 2002, included the following:

o a net one-time charge of $41 million in 2003 at ComEd as the result of an agreement described in Note 4 - Regulatory Issues,

o reduction in depreciation expense of $24 million due to the impact of lower depreciation rates at ComEd effective July 1, 2002,

o reduction of amortization expense of $16 million for nuclear decommissioning of retired plants at ComEd due to the adoption of SFAS No.
143 (see Note 2 of the Condensed Combined Notes to Consolidated Financial Statements),

o increased depreciation expense in 2003 of $10 million due to higher plant in service balances,

o lower corporate allocations and executive severance costs partially offset by higher pension and postretirement benefit costs totaling $10 million in 2003, and

o additional gross receipts tax expense of $7 million related to additional revenues (gross receipts taxes are recorded in Revenues and Taxes Other Than Income and have no net impact on operating income).

The changes in income before income taxes and cumulative effect of a change in accounting principle for the three months ended March 31, 2003 compared to the same period in 2002, included the following:

o a decrease in interest expense of $25 million primarily attributable to less outstanding debt and refinancing of existing debt at lower interest rates, and
o the reversal in 2003 of a $12 million reserve for a potential plant disallowance as the result of an agreement described in Note 4 - Regulatory Issues.

Energy Delivery's effective income tax rate was 37.1% for the three months ended March 31, 2003, compared to 37.0% for the same period in 2002.

Due to the adoption of SFAS No. 143, ComEd recorded cumulative effect of a change in accounting principle of $5 million, net of income taxes, in the three months ended March 31, 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 are as follows:

                                                           Three Months Ended March 31,
                                                           ---------------------------
Retail Deliveries - (in gigawatthours (GWhs))(1)           2003         2002     Variance      % Change
--------------------------------------------------------------------------------------------------------
Bundled Deliveries (2)
Residential                                              10,001        8,465        1,536       18.1%
Small Commercial & Industrial                             7,407        7,207          200        2.8%
Large Commercial & Industrial                             4,966        5,307         (341)      (6.4%)
Public Authorities & Electric Railroads                   1,669        1,994         (325)     (16.3%)
-----------------------------------------------------------------------------------------
    Total Bundled Deliveries                             24,043       22,973        1,070        4.7%
-----------------------------------------------------------------------------------------
Unbundled Deliveries (3)
Alternative Energy Suppliers
Residential                                                 264          792         (528)     (66.7%)
Small Commercial & Industrial                             1,550        1,100          450       40.9%
Large Commercial & Industrial                             2,042        1,489          553       37.1%
Public Authorities & Electric Railroads                     282          138          144      104.3%
-----------------------------------------------------------------------------------------
                                                          4,138        3,519          619       17.6%
-----------------------------------------------------------------------------------------
PPO (ComEd Only)
Small Commercial & Industrial                               794          763           31        4.1%
Large Commercial & Industrial                             1,433        1,311          122        9.3%
Public Authorities & Electric Railroads                     537          242          295      121.9%
-----------------------------------------------------------------------------------------
                                                          2,764        2,316          448       19.3%
-----------------------------------------------------------------------------------------
    Total Unbundled Deliveries                            6,902        5,835        1,067       18.3%
-----------------------------------------------------------------------------------------
Total Retail Deliveries                                  30,945       28,808        2,137        7.4%
=========================================================================================

(1) One GWh is the equivalent of one million kilowatthours (kWh).
(2) Bundled service reflects deliveries to customers taking electric generation service under tariffed rates.
(3) Unbundled service reflects customers electing to receive electric generation service from an alternative energy supplier or ComEd's PPO.

                                                           Three Months Ended March 31,
                                                           ----------------------------
Electric Revenue                                                       2003         2002     Variance      % Change
-------------------------------------------------------------------------------------------------------------------
Bundled Revenues (1)
Residential                                                       $     905     $    761     $    144       18.9%
Small Commercial & Industrial                                           591          580           11        1.9%
Large Commercial & Industrial                                           340          346           (6)      (1.7%)
Public Authorities & Electric Railroads                                 106          110           (4)      (3.6%)
-----------------------------------------------------------------------------------------------------
    Total Bundled Revenues                                            1,942        1,797          145        8.1%
-----------------------------------------------------------------------------------------------------
Unbundled Revenues (2)
Alternative Energy Suppliers
----------------------------
Residential                                                              17           54          (37)      (68.5%)
Small Commercial & Industrial                                            51           17           34          n.m.
Large Commercial & Industrial                                            54           13           41          n.m.
Public Authorities & Electric Railroads                                   9            2            7          n.m.
-----------------------------------------------------------------------------------------------------
                                                                        131           86           45       52.3%
-----------------------------------------------------------------------------------------------------
PPO (ComEd Only)
----------------
Small Commercial & Industrial                                            49           43            6       14.0%
Large Commercial & Industrial                                            72           64            8       12.5%
Public Authorities & Electric Railroads                                  28           13           15      115.4%
-----------------------------------------------------------------------------------------------------
                                                                        149          120           29       24.2%
-----------------------------------------------------------------------------------------------------
    Total Unbundled Revenues                                            280          206           74       35.9%
-----------------------------------------------------------------------------------------------------
Total Electric Retail Revenues                                        2,222        2,003          219       10.9%
-----------------------------------------------------------------------------------------------------
    Wholesale and Miscellaneous Revenue (3)                             132          123            9        7.3%
-----------------------------------------------------------------------------------------------------
Total Electric Revenue                                            $   2,354     $  2,126     $    228       10.7%
=====================================================================================================

(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.
n.m. - not meaningful

The differences in three months ended March 31, 2003 electric retail revenues as compared to the same period in 2002 were attributable to the following:

                                                       Variance
--------------------------------------------------------------------
Weather                                               $     101
Rate Changes                                                 82
Volume                                                       50
Customer Choice                                             (20)
Other Effects                                                 6
--------------------------------------------------------------------
Electric Retail Revenue                               $     219
====================================================================

o Weather. The demand for electricity is impacted by weather conditions. Very warm weather in summer months and very cold weather in other months is 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 March 31, 2003 was favorable compared to the same period in 2002 as a result of colder winter weather in 2003. Heating degree-days in the ComEd and PECO service territories were 17% higher and 33% higher, respectively, in 2003 as compared to 2002.

o Rate Changes. The increase in revenues attributable to rate changes reflects the collection of additional CTC's in 2003 by ComEd of $105 million due to an increase in the number of customers choosing an alternative energy supplier and changes in the wholesale market price of electricity, net of increased mitigation factors. Increased wholesale market prices decreased revenue received under ComEd's PPO by $23 million.

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 residential and large commercial and industrial customers.

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. As of March 31, 2003, 13% 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 $39 million from customers in Illinois electing to purchase energy from an alternative retail electric supplier (ARES) or ComEd's PPO, partially offset by an increase in revenues of $19 million from customers in Pennsylvania who selected or returned to PECO as their electric supplier.

The Pennsylvania Utility Commission's (PUC) Final Electric Restructuring Order established market share thresholds (MST) for PECO 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 a 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 and the customer enrollment phase is currently in process. The randomly selected customers will be transferred to the alternative electric generation suppliers in May 2003, if they do not choose the option to not participate in the program. 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. Any customer transferred would have the right to return to PECO at any time. PECO does not expect the transfer of customers pursuant to the MST plan to have a material impact on its results of operations, financial position or cash flows.

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

                                                   Three Months Ended March 31,
                                                   ----------------------------
                                                              2003         2002     Variance      % Change
-------------------------------------------------------------------------------------------------------------
Deliveries in million cubic feet (mmcf)                     39,626       31,357        8,269       26.4%
Revenue                                                  $     288     $    209     $     79       37.8%
--------------------------------------------------------------------------------------------

The changes in gas revenue for the three months ended March 31, 2003 as compared to the same period in 2002, were as follows:

                                                                 Variance
--------------------------------------------------------------------------
Weather                                                     $      59
Volume                                                             17
Rate Changes                                                        3
--------------------------------------------------------------------------
Gas Revenue                                                 $      79
--------------------------------------------------------------------------

o Weather. The demand for gas is impacted by weather conditions. Very cold weather in non-summer months is referred to as "favorable weather conditions," because these weather conditions result in increased sales of gas. Conversely, mild weather reduces demand. The weather impact was favorable compared to the prior year as a result of colder winter weather. Heating degree-days increased 33% in the three months ended March 31, 2003 compared to the same period in 2002.
o Volume. Exclusive of weather impacts, higher delivery volume increased revenue in the three months ended March 31, 2003 compared to the same period in 2002 resulting from customer growth. Deliveries to customers, excluding the effects of weather, increased 5% in the three months ended March 31, 2003 compared to the same period in 2002.
o Rate Changes. The favorable variance in rates is attributable to a 15% increase in the purchased gas adjustment by the PUC effective March 1, 2003. The average rate per million cubic feet for the three months ended March 31, 2003 was 9% higher than the rate in the same 2002 period. PECO's gas rates are subject to periodic adjustments by the PUC and are designed to recover from or refund to customers the difference between actual cost of purchased gas and the amount included in base rates and to recover or refund increases or decreases in certain state taxes not recovered in base rates.

Results of Operations - Generation

In the second quarter of 2002, Generation early adopted FASB Emerging Issues Task Force (EITF) Issue 02-3, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" (EITF 02-3). EITF 02-3 was issued by the EITF in June 2002 and required revenues and energy costs related to energy trading contracts to be presented on a net basis in the income statement. For comparative purposes, energy costs related to energy trading have been reclassified as revenue for prior periods to conform to the net basis of presentation required by EITF 02-3.

                                                            Three Months Ended March 31,
                                                            ----------------------------
                                                                       2003         2002     Variance      % Change
------------------------------------------------------------------------------------------------------------------
Operating Revenues                                                $   1,879     $  1,461       $  418        28.6%
Revenue, net of Purchased Power & Fuel Expense                          674          633           41         6.5%
Operating Income                                                         94           89            5         5.6%
Income (Loss) Before Income Taxes and Cumulative Effect
   of Changes in Accounting Principles                                  (73)         111         (184)     (165.8%)
Income (Loss) Before Cumulative Effect of Changes in
   Accounting Principles                                                (52)          66         (118)     (178.8%)
Net Income                                                               56           79          (23)      (29.1%)
------------------------------------------------------------------------------------------------------------------

The changes in Generation's revenue, net of purchased power and fuel expense, for the three months ended March 31, 2003 compared to the same period in 2002, included the following:

o increased demand due to customers returning to PECO from alternative energy suppliers and favorable weather conditions in the ComEd and PECO service territories in 2003 resulting in net volume and price increases of $34 million,

o increases of $32 million for generation from plants acquired after the first quarter of 2002 resulting in higher market sales,

o increased revenue to ComEd of $16 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 $31 million in 2003 compared to mark-to-market gains of $6 million on hedging activities in 2002, and

o write-down of nuclear fuel of $6 million in 2003 resulting from underperforming fuel at the Quad Cities Unit 1.

The changes in operating income, other than changes in revenue net of purchased power and fuel expense, for the three months ended March 31, 2003 compared to the same period in 2002, included the following:

o higher costs of $27 million for employee medical, pension and other benefits in 2003, partially offset by a one-time executive severance charge of $19 million in 2002,

o increased O&M costs of $19 million due to asset acquisitions made after the first quarter of 2002,

o reduced refueling outage costs of $32 million resulting from fewer refueling outage days in 2003,

o additional depreciation of $15 million due to capital additions placed in service and plant acquisitions made after the first quarter of 2002, and

o increased accretion expense of $57 million primarily due to asset retirement obligation accretion due to the adoption of SFAS No. 143, partially offset by reduced decommissioning expense of $33 million.

The changes in income before income taxes and cumulative effect of changes in accounting principles for the three months ended March 31, 2003 compared to the same period in 2002, included the following:

o a pre-tax impairment charge of $200 million related to Generation's equity investment in Sithe,

o increased decommissioning trust investment income of $20 million,

o reduced equity in earnings of unconsolidated affiliates of $4 million, and

o increased interest expense of $2 million primarily due to the note payable to Sithe.

Generation's effective income tax rate was 28.8% for the three months ended March 31, 2003 compared to 40.5% for the same period in 2002. This decrease was primarily attributable to the impact of the impairment of Generation's investment in Sithe and other tax benefits recorded in 2003.

Cumulative effect of changes in accounting principles recorded in the three months ended March 31, 2003 and 2002 included income of $108 million, net of income taxes, recorded in 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.

                                            Three Months Ended March 31,
                                            ----------------------------
Sales (in GWhs)                                        2003         2002     Variance      % Change
----------------------------------------------------------------------------------------------------
Energy Delivery                                      29,346       27,750        1,596        5.8%
Exelon Energy                                         1,248        1,250           (2)      (0.2%)
Market Sales                                         23,815       19,324        4,491       23.2%
-------------------------------------------------------------------------------------
Total Sales                                          54,409       48,324        6,085       12.6%
=====================================================================================

                                            Three Months Ended March 31,
                                            ----------------------------
Supply of Sales (in GWhs)                              2003         2002     Variance      % Change
----------------------------------------------------------------------------------------------------
Nuclear Generation (1)                               29,330       27,533        1,797        6.5%
Purchases - non-trading portfolio (2)                20,029       18,093        1,936       10.7%
Fossil and Hydro Generation                           5,050        2,698        2,352       87.2%
-------------------------------------------------------------------------------------
Total Supply                                         54,409       48,324        6,085       12.6%
=====================================================================================
(1) Excluding AmerGen.
(2) Including purchased power agreements with AmerGen.

         Trading volume of 9,527 GWhs and 14,239 GWhs for the three months ended
March 31, 2003 and 2002, respectively, is not included in the table above.

Generation's average margin and other operating data for the three months ended March 31, 2003 and 2002 were as follows:

                                                                      Three Months Ended March 31,
                                                                      ----------------------------
 ($/MWh)                                                                    2003              2002         % Change
-------------------------------------------------------------------------------------------------------------------
Average Revenue
     Energy Delivery                                                 $    30.87       $      29.98           3.0%
     Exelon Energy                                                        43.28              45.60          (5.1%)
     Market Sales                                                         37.05              28.15          31.6%
     Total - excluding the trading portfolio                              33.96              29.63          14.6%

Average Supply Cost (1) - excluding the trading portfolio            $    21.29       $      16.74          27.2%

Average Margin - excluding the trading portfolio                     $    12.67       $      12.89          (1.7%)
-------------------------------------------------------------------------------------------------------------------
(1)      Average supply cost includes purchased power and fuel costs.


                                                                       Three Months Ended March 31,
                                                                       ----------------------------
                                                                                              2003             2002
-------------------------------------------------------------------------------------------------------------------
Nuclear fleet capacity factor (1)                                                             94.4%            90.3%
Nuclear fleet production cost per MWh (1)                                               $    12.80        $   14.26
Average purchased power cost for wholesale operations per MWh                           $    41.75        $   34.26
-------------------------------------------------------------------------------------------------------------------
(1) Including AmerGen and excluding Salem.

Generation's MWh deliveries increased 12.6% in the three months ended March 31, 2003 as compared to the same period in 2002. Increased deliveries were a result of favorable weather conditions, which increased the demand for Energy Delivery and higher market sales attributable to the increased supply from acquired generation and power uprates at existing facilities.

The factors below contributed to the overall reduction in Generation's average margin for the three months ended March 31, 2003 as compared to the same period in 2002.

Generation's average revenue per MWh was affected by:

o increased weighted average on and off-peak prices per MWh for supply agreements with ComEd,

o higher prices per MWh on sales under supply agreements with PECO, and

o higher market prices.

Generation's supply mix changed due to:

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, a peaking facility placed in service in July 2002 and the Sithe New England (currently known as Exelon New England) plants acquired in November 2002, which in total account for an increase of 2,500 GWhs, and

o increased quantity of purchased power at higher prices to service greater than anticipated customer loads.

Higher nuclear capacity factors and decreased nuclear production costs are primarily due to 30 fewer planned refueling outage days, resulting in a $32 million decrease in outage costs, in the three months ended March 31, 2003 as compared to the same period in 2002. Additionally, the three months ended March 31, 2003 included three unplanned outages compared to five unplanned outages during the three months ended March 31, 2002.

                                                            Three Months Ended March 31,
                                                            ----------------------------
                                                                       2003         2002     Variance      % Change
--------------------------------------------------------------------------------------------------------------------
Operating Revenues                                                 $    580      $   490        $  90         18.4%
Operating Income (Loss)                                                 (27)         (34)           7        (20.6%)
Income (Loss) Before Income Taxes and Cumulative Effect
   of Changes in Accounting Principles                                  (30)         (47)          17        (36.2%)
Income (Loss) Before Cumulative Effect of Changes in
   Accounting Principles                                                (17)         (28)          11        (39.3%)
Net Income (Loss)                                                       (18)        (271)         253        (93.4%)
---------------------------------------------------------------------------------------------------------

The changes in Enterprises' operating income (loss) for the three months ended March 31, 2003 compared to the same period in 2002, included the following:

o lower revenues of $14 million from Exelon Services as a result of reduced construction projects offset by lower construction costs of $13 million,

o higher gross margins at InfraSource Inc. of $2 million primarily resulting from bad debt expense recorded in 2002 as a result of the downturn in the telecommunications industry,

o lower gross margins at Exelon Energy of $12 million resulting from the reversal of mark-to-market adjustments of $7 million and additional gas supply costs of $11 million attributable to purchases at spot rates for gas in the Northeast, offset by higher gross margins of $6 million in the Midwest attributable to increased unit margins and higher volumes due to colder weather,

o reductions in general and administrative expenses of $10 million primarily resulting from Exelon's 2002 Cost Management Initiative, and

o accelerated depreciation of assets in 2002 relating to Exelon Energy's discontinuance of retail sales in the PJM region of $7 million.

The changes in income (loss) before income taxes and cumulative effect of changes in accounting principles for the three months ended March 31, 2003 compared to the same period in 2002, included the following:

o lower interest expense of $2 million,

o higher equity in earnings of unconsolidated affiliates of $4 million resulting from the discontinuance of losses from the AT&T Wireless investment as a result of its sale in the second quarter of 2002, and $3 million resulting from lower costs at a communications joint venture, and

o impairment of a software-related investment of $5 million due to an other than temporary decline in value. In the first quarter of 2002, Enterprises had a $2 million net realized loss on a communications investment and a $2 million impairment of a communications investment.

The effective income tax rate was 43.3% for the three months ended March 31, 2003, compared to 40.4% for the same period in 2002. This increase in the effective tax rate was attributable to various income tax related items totaling $1 million.

The cumulative effect of a change in accounting principles recorded in the three months ended March 31, 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 three months ended March 31, 2002 due to the adoption of SFAS No. 142 reduced net income by $243 million, net of income taxes (see Note 2 of the Condensed Combined Notes to Consolidated Financial Statements).

Enterprises continues to pursue the divestiture of certain 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.

Cash Flows from Operating Activities

Cash flows provided by operations for the three months ended March 31, 2003 were $383 million compared to $826 million in the three months ended March 31, 2002. The decrease in cash flows was primarily attributable to a $305 million decrease in working capital. In the first quarter of 2003, approximately 40% of cash flows provided by operations were provided by Energy Delivery and 60% were provided by Generation. Enterprises' cash flows from operations were immaterial to Exelon for the three months ended March 31, 2003. 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 and customer choice on its revenues. Generation's cash flows from operating activities primarily result from the sale of electric energy to wholesale customers, including Energy Delivery and Enterprises. Generation's future cash flow from operating activities will depend upon future demand and market prices for energy and the ability to continue to produce and supply power at competitive costs. Although the amounts may vary from period to period as a result of the uncertainties inherent in business, Exelon expects that Energy Delivery and Generation will continue to provide a reliable and steady source of internal cash flow from operations for the foreseeable future.

Cash Flows from Investing Activities

Cash flows used in investing activities for the three months ended March 31, 2003 were $457 million, compared to $630 million for the three months ended March 31, 2002. The decrease is primarily attributable to a decrease in capital expenditures due to two scheduled refueling outages occurring during the three months ended March 31, 2003 compared to four outages in the same period in the prior year and $70 million related to liquidated damages from Raytheon (see Note 8 of the Condensed Combined Notes to Consolidated Financial Statements). Capital expenditures by business segment for the three months ended March 31, 2003 and 2002 were as follows:

                                         Three Months Ended March 31,
                                         -----------------------------
                                                2003              2002
----------------------------------------------------------------------
Energy Delivery                            $     239         $     250
Generation                                       175               308
Enterprises                                        6                18
Corporate and Other                                7                10
----------------------------------------------------------------------
Total Capital Expenditures                 $     427         $     586
======================================================================

Energy Delivery's capital expenditures for 2003 reflect the continuation of efforts to

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

Generation's capital expenditures for 2003 reflect the construction of three Exelon New England generating facilities with projected capacity of 2,421 MWs of energy, additions to and upgrades of existing facilities (including nuclear refueling outages), and nuclear fuel. In February 2002, Generation entered into an agreement to loan AmerGen up to $75 million at an interest rate of one-month LIBOR plus 2.25%. In July 2002, the loan agreement and the loan were increased to $100 million and the maturity date was extended to July 1, 2003. As of March 31, 2003, the balance of the loan to AmerGen was $35 million. 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 to or upgrades of existing facilities. All of Enterprises' capital expenditures are expected to be funded by capital contributions or borrowings from Exelon.

Cash Flows from Financing Activities

Cash flows provided by financing activities were $108 million for the three months ended March 31, 2003 compared to $15 million for the three months ended March 31, 2002. The increase is primarily attributable to an increase in net borrowings. See Notes 10 and 14 of the Condensed Combined Notes to Consolidated Financial Statements for further discussion of Exelon's debt and preferred securities financing activities in 2003.

Credit Issues

Exelon meets its short-term liquidity requirements primarily through the issuance of commercial paper by the Exelon corporate holding company (Exelon Corporate) and by ComEd, PECO and Generation. Exelon Corporate participates, along with ComEd, PECO and Generation, in a $1.5 billion unsecured 364-day revolving credit facility with a group of banks. The credit facility became effective on November 22, 2002 and includes a term-out option that allows any outstanding borrowings at the end of the revolving credit period to be repaid on November 21, 2004. Exelon Corporate may increase or decrease the sublimits of each of the participants upon written notification to the banks. As of March 31, 2003, Exelon Corporate's sublimit was $800 million, ComEd's was $100 million, PECO's was $600 million and there was no sublimit for Generation. The credit facility is used principally to support the commercial paper programs of Exelon Corporate, ComEd, PECO and Generation. At March 31, 2003, Exelon's Consolidated Balance Sheet reflected $1,150 million of commercial paper outstanding of which $250 million was classified as long-term debt. For the three months ended March 31, 2003, the average interest rate on notes payable was approximately 1.41%.

The credit facility requires Exelon Corporate, ComEd, PECO and 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 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 March 31, 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 March 31, 2003:

                                 Exelon Corporate             ComEd           PECO        Generation
-------------------------------------------------------------------------------------------------------
Credit Agreement Threshold              2.65 to 1         2.25 to 1        2.25 to 1         3.25 to 1
-------------------------------------------------------------------------------------------------------

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 and its subsidiary, Commonwealth Edison Company of Indiana, Inc., PECO, Generation and Exelon Business Services Company (BSC) may participate in the money pool as lenders and borrowers, and Exelon Corporate as a lender. Contributions to and permitted borrowings from the money pool are based 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 first quarter 2003, ComEd had various loans to Generation under the money pool. The maximum amount of loans outstanding at any time during the quarter was $335 million. As of March 31, 2003, there was no outstanding balance on these loans.

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

Exelon obtained an order from the United States Securities and Exchange Commission (SEC) under PUHCA authorizing through March 31, 2004 financing transactions, including the issuance of common stock, preferred securities, long-term debt and short-term debt, in an aggregate amount not to exceed $4 billion. As of March 31, 2003, there was $2.1 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

March 31, 2003, Exelon had provided $1.5 billion of guarantees under the SEC order. See Contractual Obligations, Commercial Commitments and Off-Balance Sheet Obligations in this section for further discussion of guarantees. The SEC order requires Exelon and ComEd to maintain a ratio of common equity to total capitalization (including securitization debt) on and after June 30, 2002 of not less than 30%. At March 31, 2003, Exelon and ComEd's common equity ratios were 32% and 46%, respectively. Exelon and ComEd expect that they will maintain a common equity ratio of at least 30%.

Under PUHCA, Exelon, ComEd, PECO and Generation can pay dividends only from retained, undistributed or current earnings. However, the SEC order granted permission to ComEd, and to Exelon, to the extent Exelon receives dividends from ComEd paid from ComEd additional paid-in-capital, to pay up to $500 million in dividends out of additional paid-in capital, although Exelon may not pay dividends out of paid-in capital after December 31, 2002 if its common equity is less than 30% of its total capitalization. At March 31, 2003, Exelon had retained earnings of $2.3 billion, including ComEd's retained earnings of $652 million, PECO's retained earnings of $447 million and Generation's undistributed earnings of $980 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 March 31, 2003, Exelon had invested $2.2 billion in EWGs, leaving $1.8 billion of investment authority under the order. Exelon's request for an additional $1.5 billion in EWG investment authorization is pending with the SEC.

Contractual Obligations, Commercial Commitments and Off-Balance Sheet Obligations

Contractual obligations represent cash obligations that are considered to be firm commitments and commercial commitments represent commitments triggered by future events. Exelon's contractual obligations and commercial commitments as of March 31, 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 residential delivery services rate proceeding, market value index proceeding, the process for competitive service declarations for large-load customers and an extension of the purchased power agreement (PPA) with Generation. The parties to the Agreement agreed to make and support a series of coordinated filings intended to lead to the issuance by the Illinois Commerce Commission
(ICC) of orders consistent with the Agreement. Those orders, which were issued on March 28, 2003, are subject to rehearing. Rehearing requests have been filed with the ICC. Rehearing requests may be considered through the middle of May 2003. The Agreement will not become effective as long as the ICC orders are subject to any rehearing request or if a stay is issued with respect to any of those orders.

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 will be adjusted upward through agreed upon "adders," which will take effect in June 2003 and will have the effect of reducing ComEd's CTC charges to customers. The estimated annual revenue impact of the reduction in CTC revenues under the Agreement is approximately $65 million to $70 million. In addition, customers will be offered an option to lock in CTC charges for longer periods. Currently, those charges are subject to change annually.

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

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

o See Notes 10 and 14 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 See Note 8 of the Condensed Combined Notes to Consolidated Financial Statements for commercial commitments tables representing Exelon's commitments not recorded on the balance sheet but potentially triggered by future events, including obligations to make payment on behalf of other parties and financing arrangements to secure their obligations.

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.

Significant Operating Trends - ComEd
                                                            Three Months Ended March 31,
                                                            ----------------------------
                                                                       2003         2002     Variance      % Change
------------------------------------------------------------------------------------------------------------
OPERATING REVENUES                                                $   1,424      $ 1,315       $  109        8.3%

OPERATING EXPENSES
     Purchased Power                                                    578          538           40        7.4%
     Operating and Maintenance                                          261          237           24       10.1%
     Depreciation and Amortization                                       94          135          (41)     (30.4%)
     Taxes Other Than Income                                             80           73            7        9.6%
-----------------------------------------------------------------------------------------------------
         Total Operating Expenses                                     1,013          983           30        3.1%
-----------------------------------------------------------------------------------------------------

OPERATING INCOME                                                        411          332           79       23.8%

OTHER INCOME AND DEDUCTIONS
     Interest Expense                                                  (110)        (126)          16      (12.7%)
     Distributions on Company-Obligated Mandatorily
       Redeemable Preferred Securities of Subsidiary Trusts
       Holding Solely the Company's Subordinated Debt Securities         (7)          (7)          --        --
     Other, Net                                                          22           14            8       57.1%
-----------------------------------------------------------------------------------------------------
         Total Other Income and Deductions                              (95)        (119)          24      (20.2%)
-----------------------------------------------------------------------------------------------------

INCOME BEFORE INCOME TAXES AND CUMULATIVE
   EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE                           316          213          103       48.4%

INCOME TAXES                                                            126           84           42       50.0%
-----------------------------------------------------------------------------------------------------

NET INCOME BEFORE CUMULTIVE EFFECT OF A CHANGE IN
   ACCOUNTING  PRINCIPLE                                                190          129           61       47.3%

CUMULTIVE EFFECT OF A CHANGE IN ACCOUNTING
   PRINCIPLE                                                              5           --            5        n.m.
-----------------------------------------------------------------------------------------------------
NET INCOME                                                        $     195      $   129        $  66       51.2%
=====================================================================================================

n.m. -not meaningful

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

                                 Three Months Ended March 31,
                                 -----------------------------
Retail Deliveries - (in GWhs)              2003        2002      Variance   % Change
----------------------------------------------------------------------------------------
Bundled Deliveries (1)
Residential                                 6,886     6,409        477         7.4%
Small Commercial & Industrial               5,627     5,450        177         3.2%
Large Commercial & Industrial               1,484     1,956       (472)      (24.1%)
Public Authorities & Electric Railroads     1,416     1,801       (385)      (21.4%)
----------------------------------------------------------------------------------------
                                           15,413    15,616       (203)       (1.3%)
----------------------------------------------------------------------------------------
Unbundled Deliveries (2)
ARES
Small Commercial & Industrial               1,348     1,004        344        34.3%
Large Commercial & Industrial               1,832     1,386        446        32.2%
Public Authorities & Electric Railroads       282       138        144       104.3%
----------------------------------------------------------------------------------------
                                            3,462     2,528        934        36.9%
----------------------------------------------------------------------------------------
PPO
Small Commercial & Industrial                 793       763         30         3.9%
Large Commercial & Industrial               1,433     1,311        122         9.3%
Public Authorities & Electric Railroads       537       242        295       121.9%
----------------------------------------------------------------------------------------
                                            2,763     2,316        447        19.3%
----------------------------------------------------------------------------------------
     Total Unbundled Deliveries             6,225     4,844      1,381        28.5%
----------------------------------------------------------------------------------------
Total Retail Deliveries                    21,638    20,460      1,178         5.8%
========================================================================================

(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.

                                Three Months Ended March 31,
                                ---------------------------
Electric Revenue                             2003      2002    Variance     % Change
----------------------------------------------------------------------------------------
Bundled Revenues (1)
Residential                               $   546   $   518    $    28         5.4%
Small Commercial & Industrial                 397       391          6         1.5%
Large Commercial & Industrial                  74       102        (28)      (27.5%)
Public Authorities & Electric Railroads        84        92         (8)       (8.7%)
----------------------------------------------------------------------------------------
                                            1,101     1,103         (2)       (0.2%)
----------------------------------------------------------------------------------------
Unbundled Revenues (2)
ARES
Small Commercial & Industrial                  41        12         29          n.m.
Large Commercial & Industrial                  49        10         39          n.m.
Public Authorities & Electric Railroads         9         2          7          n.m.
----------------------------------------------------------------------------------------
                                               99        24         75          n.m.
----------------------------------------------------------------------------------------
PPO
Small Commercial & Industrial                  50        43          7        16.3%
Large Commercial & Industrial                  72        64          8        12.5%
Public Authorities & Electric Railroads        27        13         14       107.7%
----------------------------------------------------------------------------------------
                                              149       120         29        24.2%
----------------------------------------------------------------------------------------
Total Unbundled Revenues                      248       144        104        72.2%
Total Electric Retail Revenues              1,349     1,247        102         8.2%
Wholesale and Miscellaneous Revenue (3)        75        68          7        10.3%
----------------------------------------------------------------------------------------
Total Electric Revenue                    $ 1,424   $ 1,315    $   109         8.3%
========================================================================================

(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.
n.m. - not meaningful

The changes in electric retail revenues for the three months ended March 31, 2003, as compared to the same period in 2002, are attributable to the following:

                                               Variance
--------------------------------------------------------
Rate Changes                               $       82
Weather                                            54
Customer Choice                                   (39)
Volume                                              7
Other Effects                                      (2)
--------------------------------------------------------
Electric Retail Revenue                    $      102
--------------------------------------------------------

o Rate Changes. The increase in revenues attributable to rate changes reflects the collection of additional CTC's in 2003 by ComEd of $105 million due to an increase in the number of customers choosing an alternative energy supplier and changes in the wholesale market price of electricity, net of increased mitigation factors. Increased wholesale market prices decreased revenue received under ComEd's PPO by $23 million.

o Weather. The demand for electricity is impacted by weather conditions. Very warm weather in summer months and very cold weather in other months is 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 March 31, 2003 was favorable compared to the same period in 2002 as a result of colder winter weather in 2003. Heating degree-days increased 17% in the three months ended March 31, 2003 compared to the same 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 March 31, 2003, no alternative electric supplier has sought approval from the ICC, and no electric utilities have chosen to enter the ComEd residential market for the supply of electricity.

The decrease in revenues reflects customers in Illinois electing to purchase energy from an ARES or the PPO. As of March 31, 2003, approximately 22,700 retail customers had elected to purchase energy from an ARES or the ComEd PPO. This represents an increase in delivered MWhs to such customers from approximately 4.8 million for the three months ended March 31, 2002 to 6.2 million for the three months ended March 31, 2003, or from 24% to 29% of total quarterly 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 small commercial and industrial.

The $7 million increase in wholesale and miscellaneous revenue for the three months ended March 31, 2003 as compared to the three months ended March 31, 2002 was due primarily to a $5 million increase in sales for resale to municipalities and others as a result of a 17% increase in heating degree-days in 2003.

Purchased Power
Purchased power expense increased $40 million, or 7% for the three months ended March 31, 2003. The increase in purchased power expense was primarily attributable to a $20 million increase due to favorable weather conditions, an increase of $12 million due to higher volume, $17 million due to pricing changes related to ComEd's PPA with Generation and an increase of $16 million under the PPA related to decommissioning collections associated with the adoption of SFAS No. 143 that were not included in purchased power in 2002, offset by a $28 million decrease as a result of customers choosing to purchase energy from an ARES. The $16 million increase in purchased power expense related to SFAS No. 143 is offset by lower regulatory asset amortization.

Operating and Maintenance
Operating and maintenance (O&M) expense increased $24 million, or 10%, for the three months ended March 31, 2003. The increase in O&M expense was primarily attributable to a net one-time charge of $41 million in 2003 as the result of the Agreement as more fully described in Note 4 - Regulatory Issues, offset by higher corporate allocations in 2002 due to executive severance.

                                                    Three Months Ended March 31,
                                                    ----------------------------
                                                          2003              2002         Variance          % Change
-------------------------------------------------------------------------------------------------------------------
Depreciation Expense                                 $      75         $      91        $     (16)          (17.6%)
Recoverable Transition Costs Amortization                   11                23              (12)          (52.2%)
Other Amortization Expense                                   8                21              (13)          (61.9%)
--------------------------------------------------------------------------------------------------
Total Depreciation and Amortization                  $      94         $     135        $     (41)          (30.4%)
==================================================================================================

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

Recoverable transition costs amortization decreased in the three months ended March 31, 2003 compared to the same period in 2002. The decrease is a result of the extension of the rate freeze through 2006 which occurred in June 2002. ComEd expects to fully recover its recoverable transition costs regulatory asset balance of $164 million by 2006. Consistent with the provision of the Illinois legislation, regulatory assets may be recovered at amounts that provide ComEd an earned return on common equity within the Illinois legislation earnings threshold.

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

Taxes Other Than Income
Taxes other than income increased by $7 million or 10%, as a result of a $4 million increase in real estate and municipal taxes and $1 million in Illinois Public Utility Fund taxes which were not charged in 2002.

Interest Charges
Interest charges consist of interest expense and distributions on Company-Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trusts. Interest charges decreased $16 million, or 13%, for the three months ended March 31, 2003. The decrease in interest expense was primarily attributable to the impact of lower interest rates for the three months ended March 31, 2003 as compared to the three months ended March 31, 2002 and the annual retirement of $340 million in Transitional Trust Notes.

Other, Net
Other, Net increased income by $8 million for the three months ended March 31, 2003. The increase was primarily attributable to the reversal of a $12 million reserve in 2003 for a potential plant disallowance as the result of the Agreement as more fully described in Note 4 to the Condensed Combined Notes to Consolidated Financial Statements.

Income Taxes
The effective income tax rate was 39.9% for the three months ended March 31, 2003, compared to 39.4% for the three months ended March 31, 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.

LIQUIDITY AND CAPITAL RESOURCES

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

Cash Flows from Operating Activities

Cash flows provided by operations were $67 million for the three months ended March 31, 2003 compared to $278 million for the three months ended March 31, 2002. The decrease in cash flows in 2003 was primarily attributable to a $216 million decrease in working capital as a result of the paydown of intercompany payables to affiliates and other outstanding liabilities, a decrease in depreciation and amortization of $41 million offset by an increase in net income of $66 million. ComEd's future cash flows will depend upon the ability to achieve cost savings in operations and the impact of the economy, weather, and customer choice on its revenues. Although the amounts may vary from period to period as a result of uncertainties inherent in the business, ComEd expects to continue to provide a reliable and steady source of internal cash flow from operations for the foreseeable future.

Cash Flows from Investing Activities

Cash flows used in investing activities were $164 million for the three months ended March 31, 2003 compared to $175 million for the three months ended March 31, 2002. The decrease in cash flows used in investing activities in 2003 was primarily attributable to an $8 million decrease in capital expenditures.

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

Cash Flows from Financing Activities

Cash flows from financing activities were $113 million for the three months ended March 31, 2003 as compared to cash flows used in financing of $44 million for the three months ended March 31, 2002. Cash flows from financing activities were primarily attributable to debt issuance partially offset by retirements and redemptions and payments of dividends to Exelon. The increase in cash flows from financing activities is primarily attributable to increased debt and preferred securities issuances of $500 million partially offset by increased debt and preferred securities redemptions of $306 million and increased interest rate swap settlement payments of $34 million. See Notes 10 and 14 of the Condensed Combined Notes to Consolidated Financial Statements for further discussion of ComEd's debt and preferred securities financing activities. ComEd paid a $120 million dividend to Exelon during the three months ended March 31, 2003 compared to a $118 million dividend for the three months ended March 31, 2002.

Credit Issues

ComEd meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from Exelon's intercompany money pool. ComEd, along with Exelon, PECO, and Generation, participates in a $1.5 billion unsecured 364-day revolving credit facility with a group of banks. The credit facility that became effective on November 22, 2002 includes a term-out option that allows any outstanding borrowings at the end of the revolving credit period to be repaid on November 21, 2004. Exelon may increase or decrease the sublimits of each of the participants upon written notification to the banks. As of March 31, 2003, ComEd's sublimit was $100 million. The credit facility is used principally to support ComEd's commercial paper program. At March 31, 2003, ComEd's Consolidated Balance Sheet reflects $45 million in commercial paper outstanding. For the three months ended March 31, 2003, the average interest rate on notes payable was approximately 1.48%.

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 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 March 31, 2003. At March 31, 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 and its subsidiary Commonwealth Edison of Indiana, Inc., PECO, Generation and BSC may participate in the money pool as lenders and borrowers, and Exelon 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, although Exelon is not permitted to be a net borrower from the money pool. Interest on borrowings is based on short-term market rates of interest or specific borrowing rates if the funds are provided by external financing. There were no material money pool transactions in 2002. During the first quarter 2003, ComEd had various loans to Generation under the money pool. The maximum amount of outstanding loans at any time during the quarter was $335 million. As of March 31, 2003, there was no outstanding balance on these loans.

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

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

transitional trust notes). At March 31, 2003, ComEd had retained earnings of $652 million and its common equity ratio was 46%.

Long-term debt included $1.9 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 March 31, 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 residential 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. The parties to the Agreement agreed to make and support a series of coordinated filings intended to lead to the issuance by the ICC of orders consistent with the Agreement. Those orders, which were issued on March 28, 2003, are subject to rehearing. Rehearing requests have been filed with the ICC. Rehearing requests may be considered through the middle of May 2003. The Agreement will not become effective as long as the ICC orders are subject to any rehearing request or if a stay is issued with respect to any of those orders.

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 will be adjusted upward through agreed upon "adders," which will take effect in June 2003, and would have the effect of reducing ComEd's CTC charges to customers. The estimated annual revenue impact of the reduction in CTC revenues under the Agreement would be approximately $65 million to $70 million. In addition, customers will be offered an option to lock in CTC charges for longer periods. Currently, those charges are subject to change annually.

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. The fees for these agreements are contingent upon a successful outcome and are based upon a percentage of the refunds recovered from the IRS, if any. As

such, ComEd would have positive net cash flows related to these agreements if any fees are paid to the tax consultant. These potential tax benefits and associated fees could be material to the financial position, results of operations and cash flows of ComEd. ComEd cannot predict the timing of the final resolution of these refund claims.

o See Notes 10 and 14 to the Condensed Combined Notes to Consolidated Financial Statements for discussion of material changes in ComEd's debt and preferred securities obligations from those set forth in the 2002 Form 10-K.

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

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.

                                                            Three Months Ended March 31,
                                                            ---------------------------
                                                                       2003         2002     Variance      % Change
-------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES                                                $   1,217       $1,020       $  197       19.3%

OPERATING EXPENSES
     Purchased Power                                                    422          351           71       20.2%
     Fuel                                                               191          135           56       41.5%
     Operating and Maintenance                                          139          136            3        2.2%
     Depreciation and Amortization                                      120          112            8        7.1%
     Taxes Other Than Income                                             63           59            4        6.8%
------------------------------------------------------------------------------------------------------
         Total Operating Expenses                                       935          793          142       17.9%
------------------------------------------------------------------------------------------------------

OPERATING INCOME                                                        282          227           55       24.2%
------------------------------------------------------------------------------------------------------

OTHER INCOME AND DEDUCTIONS
     Interest Expense                                                   (86)         (95)           9       (9.5%)
     Distributions on Company-Obligated Mandatorily
       Redeemable Preferred Securities of a Partnership
       which Holds Solely Subordinated Debentures of
       the Company                                                       (2)          (2)          --         --
     Other, Net                                                           9            1            8        n.m.
------------------------------------------------------------------------------------------------------
         Total Other Income and Deductions                              (79)         (96)          17      (17.7%)
------------------------------------------------------------------------------------------------------

INCOME BEFORE INCOME TAXES                                              203          131           72       55.0%

INCOME TAXES                                                             66           42           24       57.1%
------------------------------------------------------------------------------------------------------

NET INCOME                                                              137           89           48       53.9%
Preferred Stock Dividends                                                (2)          (2)          --         --
------------------------------------------------------------------------------------------------------

NET INCOME ON COMMON STOCK                                        $     135       $   87        $  48       55.2%
======================================================================================================
n.m. - not meaningful

Net Income
Net income on common stock increased $48 million, or 55% for the three months ended March 31, 2003 as compared to the same period in 2002. The increase was a result of higher sales volume and lower interest expense on debt, partially offset by increased income taxes and depreciation and amortization expense.

                                                    Three Months Ended March 31,
                                                    ----------------------------
Retail Deliveries - (in GWhs)                             2003              2002         Variance         % Change
-------------------------------------------------------------------------------------------------------------------
Bundled Deliveries (1)
Residential                                              3,115             2,056            1,059          51.5%
Small Commercial & Industrial                            1,780             1,757               23           1.3%
Large Commercial & Industrial                            3,482             3,351              131           3.9%
Public Authorities & Electric Railroads                    253               193               60          31.1%
-------------------------------------------------------------------------------------------------------------------
                                                         8,630             7,357            1,273          17.3%
-------------------------------------------------------------------------------------------------------------------
Unbundled Deliveries (2)
Residential                                                264               792             (528)        (66.7%)
Small Commercial & Industrial                              202                96              106         110.4%
Large Commercial & Industrial                              210               103              107         103.9%
Public Authorities & Electric Railroads (3)                 --                --               --           0.0%
-------------------------------------------------------------------------------------------------------------------
                                                           676               991             (315)        (31.8%)
-------------------------------------------------------------------------------------------------------------------
Total Retail Deliveries                                  9,306             8,348              958          11.5%
===================================================================================================================

(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 sales to Public  Authorities  and Electric  Railroads were less than
     one GWh per quarter.

                               Three Months Ended March 31,
                               ----------------------------
Electric Revenue                               2003    2002   Variance    % Change
--------------------------------------------------------------------------------------
Bundled Revenue (1)
Residential                                   $ 359   $ 243    $ 116        47.7%
Small Commercial & Industrial                   194     189        5         2.6%
Large Commercial & Industrial                   266     244       22         9.0%
Public Authorities & Electric Railroads          22      18        4        22.2%
--------------------------------------------------------------------------------------
                                                841     694      147        21.2%
--------------------------------------------------------------------------------------
Unbundled Revenue (2)
Residential                                      17      54      (37)      (68.5%)
Small Commercial & Industrial                    10       5        5       100.0%
Large Commercial & Industrial                     6       3        3       100.0%
Public Authorities & Electric Railroads (3)    --      --       --            --
--------------------------------------------------------------------------------------
                                                 33      62      (29)      (46.8%)
--------------------------------------------------------------------------------------
Total Electric Retail Revenues                  874     756      118        15.6%
Wholesale and Miscellaneous Revenue (4)          55      55     --            --
--------------------------------------------------------------------------------------
Total Electric Revenue                        $ 929   $ 811    $ 118        14.5%
======================================================================================

(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 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.

The changes in electric retail revenues for the three months ended March 31, 2003, as compared to the same period in 2002, are as follows:

                                                    Variance
----------------------------------------------------------------
Weather                                               $47
Volume                                                 43
Customer Choice                                        19
Other Effects                                           9
-----------------------------------------------------------------
Retail Revenue                                       $118
-----------------------------------------------------------------

o Weather. The weather impact was favorable compared to the prior year as a result of colder winter weather. Heating degree-days increased 33% for the three months ended March 31, 2003 compared to the same period in 2002.

o Volume. Exclusive of weather impacts, higher delivery volume affected PECO's revenue by $43 million compared to the same period in 2002 primarily related to increases in the residential and large commercial and industrial customer classes.

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.

As of March 31, 2003, the customer load served by alternative suppliers was 1,062 MWs or 13.1% as compared to 1,010 MWs or 13.1% as of March 31, 2002. For the three months ended March 31, 2003, the percent of PECO's total retail deliveries for which PECO was the electric supplier was 92.8% compared to 88.2% in 2002. As of March 31, 2003, the

number of customers served by alternative suppliers was 273,724 or 17.9% as compared to 357,789 or 23.4% as of March 31, 2002. The increases in customers and the percentage of load served by PECO primarily resulted from customers selecting or returning to PECO as their electric generation supplier.

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 and the customer enrollment phase is currently in process. The randomly selected customers will be transferred to the alternative electric generation suppliers in May 2003, if they do not choose the option to not participate in the program. 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. Any customer transferred would have the right to return to PECO at any time. PECO does not expect the transfer of customers pursuant to the MST plan to have a material impact on its results of operations, financial position or cash flows.

o Other Effects. The increase in revenues attributable to rate changes primarily reflects an increase in the average price mix related to the large commercial and industrial customer class as compared to the same period in 2002.

PECO's gas sales statistics for the three months ended March 31, 2003 as compared to the same period in 2002 are as follows:

                                             Three Months Ended March 31,
                                             ----------------------------
                                                        2003         2002     Variance      % Change
----------------------------------------------------------------------------------------------------
Deliveries in mmcf                                    39,626       31,357        8,269       26.4%
Revenue                                            $     288     $    209     $     79       37.8%
---------------------------------------------------------------------------------------

         The changes in gas revenue for the three  months  ended March 31, 2003,
as compared to the same period in 2002, are as follows:

                                                                          Variance
----------------------------------------------------------------------------------------
Weather                                                                $      59
Volume                                                                        17
Rate Changes                                                                   3
----------------------------------------------------------------------------------------
Gas Revenue                                                            $      79
========================================================================================

o Weather. The weather impact was favorable compared to the prior year as a result of colder winter weather. Heating degree-days increased 33% in the three months ended March 31, 2003 compared to the same period in 2002.

o Volume. Exclusive of weather impacts, higher delivery volume increased revenue in the three months ended March 31, 2003 compared to the same period in 2002 resulting from customer growth. Deliveries to customers, excluding the effects of weather, increased 5% in the three months ended March 31, 2003 compared to the same period in 2002.

o Rate Changes. The favorable variance in rates is attributable to a 15% increase in the purchased gas adjustment by the PUC effective March 1, 2003. The average rate per million cubic feet for the three months ended March 31, 2003 was 9% higher than the same 2002 period. PECO's gas rates are subject to periodic adjustments by the PUC and are designed to recover from or refund to customers the difference between actual cost of purchased gas and the amount included in base rates and to recover or refund increases or decreases in certain state taxes not recovered in base rates.

Purchased Power
Purchased power expense for the three months ended March 31, 2003 increased $71 million as compared to the same period in 2002. The increase in purchased power expense was primarily attributable to $22 million as a result of favorable weather conditions, $17 million related to higher PJM ancillary charges, $16 million from customers in Pennsylvania selecting or returning to PECO as their electric generation supplier and $16 million attributable to higher electric delivery volume.

Fuel
Fuel expense for the three months ended March 31, 2003 increased $56 million as compared to the same period in 2002. This increase was primarily attributable to $40 million as a result of favorable weather conditions, $8 million attributable to higher delivery volumes and $3 million from higher gas prices.

Operating and Maintenance
O&M expense for the three months ended March 31, 2003 increased $3 million, or 2%, as compared to the same period in 2002. The increase in O&M expense was primarily attributable to $4 million of incremental storm costs in 2003, $4 million of additional employee benefits costs and $8 million of additional miscellaneous other net positive impacts partially offset by $7 million related to lower corporate allocations and $6 million of lower costs associated with the deployment of automated meter reading technology.

                                                    Three Months Ended March 31,
                                                    ----------------------------
                                                          2003              2002         Variance          % Change
--------------------------------------------------------------------------------------------------------------------
Competitive Transition Charge Amortization             $    81         $      75        $       6              8.0%
Depreciation Expense                                        33                32                1              3.1%
Other Amortization Expense                                   6                 5                1             20.0%
----------------------------------------------------------------------------------------------------
Total Depreciation and Amortization                    $   120         $     112        $       8              7.1%
====================================================================================================

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 three months ended March 31, 2003 increased $4 million, or 7%, as compared to the same period in 2002. The increase was primarily attributable to $7 million of additional gross receipts tax related to additional revenues, partially offset by a $2 million decrease in real estate taxes.

Interest Charges
Interest charges consist of interest expense and distributions on Company-Obligated Mandatorily Redeemable Preferred Securities of a Partnership (COMRPS). Interest charges decreased $9 million, or 10%, in the three months ended March 31, 2003 as compared to the same period in 2002. The decrease was primarily attributable to lower interest expense on long-term debt of $9 million as a result of scheduled principal payments and refinancing of existing debt at lower interest rates.

Other, Net
Other, Net increased income by $8 million in the three months ended March 31, 2003 as compared to the same period in 2002. The increase in other income was primarily attributable to higher interest income of $5 million and the favorable settlement of a customer contract of $3 million.

Income Taxes
The effective tax rate was 32.5% for the three months ended March 31, 2003 as compared to 32.1% for the same period in 2002.

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 three months ended March 31, 2003 were consistent as compared to the same period in 2002.

LIQUIDITY AND CAPITAL RESOURCES

PECO's business is capital intensive and requires considerable capital resources. PECO's capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing including the issuance of commercial paper or participation in the intercompany money pool. 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.

Cash Flows from Operating Activities

Cash flows provided by operations for the three months ended March 31, 2003 and 2002 were $126 million and $100 million, respectively. The increase in cash flows was primarily attributable to a $99 million increase in working capital and a $48 million increase to net income, partially offset by a $66 million decrease in deferred taxes and a $62 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 and customer choice on its revenues. Although the amounts may vary from period to period as a result of the uncertainties inherent in its business, PECO expects that it will continue to provide a reliable and steady source of internal cash flow from operations for the foreseeable future.

Cash Flows from Investing Activities

Cash flows used in investing activities for the three months ended March 31, 2003 were $59 million, compared to $65 million for the three months ended March 31, 2002. The decrease in cash flows used in investing activities was primarily attributable to a decrease in capital expenditures.

PECO's projected capital expenditures for 2003 are $270 million. Approximately one half of the budgeted 2003 expenditures are for capital additions to support customer and load growth and the remainder for additions and upgrades to existing facilities. PECO anticipates that its capital expenditures will be funded by internally generated funds, borrowings, the issuance of preferred securities, or capital contributions from Exelon. PECO's proposed capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.

Cash Flows from Financing Activities

Cash flows used in financing activities for the three months ended March 31, 2003 and 2002 were $26 million and $36 million, respectively. Cash flows used in financing activities are primarily attributable to debt service and payment of dividends to Exelon. The decrease in cash flows used in financing activities is primarily attributable to additional issuances of long-term debt in the first quarter of 2003 of $250 million, partially offset by additional debt service of $204 million. See Notes 10 and 14 of the Condensed Combined Notes to Consolidated Financial Statements for further discussion of PECO's debt financing activities. For the three months ended March 31, 2003, PECO paid Exelon $89 million in common stock dividends compared to $85 million for the three months ended March 31, 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 March 31, 2003, PECO's sublimit was $600 million. The credit facility is used by PECO principally to support its commercial paper program. At March 31, 2003, PECO's Consolidated Balance Sheet reflects $493 million in commercial paper outstanding, of which $243 million is classified as notes payable and $250 million is classified as long-term debt. For the three months ended March 31, 2003, the average interest rate on notes payable was approximately 1.33%.

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 March 31, 2003. At March 31, 2003, PECO was in compliance with the credit agreement thresholds.

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.

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 and its subsidiary Commonwealth Edison of Indiana, Inc., PECO, Generation and BSC may participate in the money pool as lenders and borrowers, and Exelon 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, although Exelon is not permitted to be a net borrower from the money pool. Interest on borrowings is based on short-term market rates of interest, or, if from an external source, specific borrowing rates. There were no material money pool transactions by PECO in the first quarter of 2003.

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 March 31, 2003, PECO had retained earnings of $447 million.

Long-term debt included $4.1 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 March 31, 2003 were materially unchanged, other than in the normal course of business, from the amounts set forth in the 2002 Form 10-K except for the following:

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

o See Notes 10 and 14 of the Condensed Combined Notes to Consolidated Financial Statements for further discussion of material changes in PECO's debt obligations from those set forth in the 2002 Form 10-K.

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

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.

In the second quarter of 2002, Generation early adopted EITF 02-3. EITF 02-3 was issued by the FASB EITF in June 2002 and required revenues and energy costs related to energy trading contracts to be presented on a net basis in the income statement. For comparative purposes, energy costs related to energy trading have been reclassified as revenue for prior periods to conform to the net basis of presentation required by EITF 02-3.

                                                            Three Months Ended March 31,
                                                            ----------------------------
                                                                       2003         2002     Variance      % Change
-------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES                                                $   1,879       $1,461       $  418       28.6%

OPERATING EXPENSES
     Purchased Power                                                    841          619          222       35.9%
     Fuel                                                               364          209          155       74.2%
     Operating and Maintenance                                          487          432           55       12.7%
     Depreciation and Amortization                                       45           63          (18)     (28.6%)
     Taxes Other Than Income                                             48           49           (1)      (2.0%)
----------------------------------------------------------------------------------------------------------
         Total Operating Expenses                                     1,785        1,372          413       30.1%
----------------------------------------------------------------------------------------------------------

OPERATING INCOME                                                         94           89            5        5.6%
----------------------------------------------------------------------------------------------------------

OTHER INCOME AND DEDUCTIONS
     Interest Expense                                                   (19)         (17)          (2)      11.8%
     Equity in Earnings of Unconsolidated Affiliates, net                19           23           (4)     (17.4%)
     Other, Net                                                        (167)          16         (183)       n.m.
----------------------------------------------------------------------------------------------------------
         Total Other Income and Deductions                             (167)          22         (189)       n.m.
----------------------------------------------------------------------------------------------------------

INCOME (LOSS) BEFORE INCOME TAXES AND CUMULATIVE
    EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES                          (73)         111         (184)    (165.8%)

INCOME TAXES                                                            (21)          45          (66)    (146.7%)
----------------------------------------------------------------------------------------------------------

INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGES IN
   ACCOUNTING PRINCIPLES                                                (52)          66         (118)    (178.8%)

CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING
    PRINCIPLES, NET OF INCOME TAXES                                     108           13           95        n.m.
----------------------------------------------------------------------------------------------------------
NET INCOME                                                        $      56       $   79      $   (23)     (29.1%)
==========================================================================================================
n.m. - not meaningful

Net Income
Generation's net income decreased by $23 million, or 29%, for the three months ended March 31, 2003 compared to the same period in 2002. Income (loss) before cumulative effect of changes in accounting principles decreased by $118 million for the three months ended March 31, 2003 compared to the same period in 2002 primarily due to the after-tax impairment charge for Generation's equity investment in Sithe of $130 million and higher operating expenses, partially offset by higher revenues and investment income.

Operating Revenues
Revenues increased by $418 million, or 29% for the three months ended March 31, 2003 compared to the same period in 2002. This increase resulted primarily from a $295 million increase in energy market sales, due to regional weather-related demand. Market sales also increased $9 million for increased generation, from the fossil plants acquired after the first quarter of 2002, related to gas purchase obligations. In addition, sales to Energy Delivery increased by $85 million due to increased demand related to favorable weather in ComEd and PECO's service territories during the first quarter of 2003 compared to 2002, and customers returning to PECO from alternative energy suppliers. Revenues from Energy Delivery for the first quarter of 2003 also included $16 million from ComEd related to nuclear decommissioning cost recoveries associated with the adoption of SFAS No. 143 that was not included in 2002. Trading activity reduced revenue by $2 million during the first quarter of 2003 compared to the same period of 2002.

For the three months ended March 31, 2003 and 2002, Generation's sales and the supply of these sales were as follows:

                                                            Three Months Ended March 31,
                                                            ----------------------------
Sales (in GWhs)                                                        2003         2002     Variance      % Change
-----------------------------------------------------------------------------------------------------------------------
Energy Delivery                                                      29,346       27,750        1,596        5.8%
Exelon Energy                                                         1,248        1,250           (2)      (0.2%)
Market Sales                                                         23,815       19,324        4,491       23.2%
----------------------------------------------------------------------------------------------------------
Total Sales                                                          54,409       48,324        6,085       12.6%
==========================================================================================================

                                                            Three Months Ended March 31,
                                                            ----------------------------
Supply of Sales (in GWhs)                                              2003         2002     Variance      % Change
-----------------------------------------------------------------------------------------------------------------------
Nuclear Generation (1)                                               29,330       27,533        1,797        6.5%
Purchases - non-trading portfolio (2)                                20,029       18,093        1,936       10.7%
Fossil and Hydro Generation                                           5,050        2,698        2,352       87.2%
----------------------------------------------------------------------------------------------------------
Total Supply                                                         54,409       48,324        6,085       12.6%
==========================================================================================================
(1) Excluding AmerGen.
(2) Including purchased power agreements with AmerGen.

Trading volume of 9,527 GWhs and 14,239 GWhs for the three months ended March 31, 2003 and 2002, respectively, is not included in the table above.

Generation's average margin and other operating data for the three months ended March 31, 2003 and 2002 were as follows:

                                                                      Three Months Ended March 31,
                                                                      ----------------------------
 ($/MWh)                                                                    2003              2002         % Change
-------------------------------------------------------------------------------------------------------------------
Average Revenue
     Energy Delivery                                                 $    30.87       $      29.98           3.0%
     Exelon Energy                                                        43.28              45.60          (5.1%)
     Market Sales                                                         37.05              28.15          31.6%
     Total - excluding the trading portfolio                              33.96              29.63          14.6%

Average Supply Cost (1) - excluding trading portfolio                $    21.29       $      16.74          27.2%

Average Margin - excluding the trading portfolio                     $    12.67       $      12.89          (1.7%)

(1)  Average supply cost includes purchased power and fuel costs.

                                                                                       Three Months Ended March 31,
                                                                                       ----------------------------
                                                                                              2003             2002
-------------------------------------------------------------------------------------------------------------------
Nuclear fleet capacity factor (1)                                                             94.4%           90.3%
Nuclear fleet production cost per MWh (1)                                               $    12.80        $   14.26
Average purchased power cost for wholesale operations per MWh                           $    41.75        $   34.26
-------------------------------------------------------------------------------------------------------------------
(1) Including AmerGen and excluding Salem.

Generation's MWh deliveries increased 12.6% in the three months ended March 31, 2003 compared to the same period in 2002. Increased deliveries were a result of favorable weather conditions, which increased the demand for Energy Delivery, and higher market sales attributable to the increased supply from acquired generation and power uprates at existing facilities.

The factors below contributed to the overall reduction in Generation's average margin for the three months ended March 31, 2003 as compared to the same period in 2002.

Generation's average revenue per MWh was affected by:

o increased weighted average on and off-peak prices per MWh for supply agreements with ComEd,

o higher prices per MWh on sales under supply agreements with PECO, and

o higher market prices.

Generation's supply mix changed due to:

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, a peaking facility placed in service in July 2003 and the Exelon New England plants acquired in November 2002, which in total account for an increase of 2,500 GWhs, and

o increased quantity of purchased power at higher prices to service greater customer loads as compared to 2002.

The higher nuclear capacity factor and decreased nuclear production costs are primarily due to 30 fewer planned refueling outage days, resulting in a $32 million decrease in outage

costs, in the three months ended March 31, 2003 as compared to the same period in 2002. Additionally, the three months ended March 31, 2003 included three unplanned outages compared to five unplanned outages during the three months ended March 31, 2002.

Purchased Power
Purchased power increased $222 million, or 36%, for the three months ended March 31, 2003 compared to the same period in 2002 due to $185 million related to higher market prices and increased purchases. Increased purchases were due to higher market sales and increased demand from ComEd and PECO. The increase in purchased power also reflects a $31 million loss on mark-to-market hedging activity for the three months ended March 31, 2003 compared to a $6 million gain in the same period in 2002.

Fuel
Fuel expense increased $155 million, or 74%, for the three months ended March 31, 2003 compared to the same period in 2002. This increase is primarily due to the higher generation to meet increased demand from ComEd and PECO and higher market sales. Fossil and other fuel expense increased $140 million, as a result of operating the generation plants acquired after the first quarter of 2002. Increased fossil fuel expense includes $9 million related to increased market sales, from the generating plants acquired after the first quarter of 2002, related to gas purchase obligations. Nuclear fuel expense increased $19 million, reflecting higher nuclear generation and $6 million due to additional fuel amortization resulting from under performing fuel at the Quad Cities Unit 1, which will be completely replaced in May 2003. The second quarter of 2003 will include approximately $13 million of additional fuel amortization related to Quad Cities Unit 1. These increases in fuel expense were partially offset by a $4 million loss on emissions allowance sales recorded in 2002.

Operating and Maintenance
O&M expense increased $55 million, or 13%, for the three months ended March 31, 2003 compared to the same period in 2002. The increase in O&M expense was primarily attributable to $39 million of accretion expense which was recorded as depreciation and amortization expense prior to the adoption of SFAS No. 143, $18 million of accretion expense related to SFAS No. 143 to adjust the earnings impact of the net of decommissioning revenues, investment income, the accretion of the asset retirement obligation and depreciation of the Asset Retirement Cost asset (ARC) to zero, $27 million of additional employee benefits costs, and $19 million of additional expenses due to asset acquisitions made after the first quarter of 2002. This increase was partially offset by $32 million of lower nuclear refueling outage costs and a one-time executive severance expense recorded in 2002 of $19 million. For a further discussion of SFAS No. 143 see Note 2 of the Condensed Combined Notes to Consolidated Financial Statements.

Depreciation and Amortization
Depreciation and amortization expense decreased $18 million, or 29%, for the three months ended March 31, 2003 compared to the same period in 2002. The decrease was primarily attributable to a $33 million reduction in decommissioning expense as these costs are included in operating and maintenance expense after the adoption of SFAS No. 143, partially offset by $6 million of additional depreciation expense on capital additions placed in service after the first quarter of 2002, $9 million related to plant acquisitions made after the first quarter of 2002, and $1 million of depreciation for the ARC asset related to SFAS No. 143. For a further discussion of SFAS No. 143 see Note 2 of the Condensed Combined Notes to Consolidated Financial Statements.

Taxes Other Than Income
Taxes other than income decreased $1 million, or 2%, for the three months ended March 31, 2003 compared to the same period in 2002 primarily due to a $4 million decrease in payroll taxes partially offset by a $3 million increase in property taxes related to asset acquisitions made after the first quarter of 2002.

Interest Expense
Interest expense increased $2 million, or 12%, for the three months ended March 31, 2003 compared to the same period in 2002. The increase was primarily due to $3 million of additional interest expense on the $534 million note payable issued to Sithe in November 2002.

Equity in Earnings of Unconsolidated Affiliates Equity in earnings of unconsolidated affiliates decreased $4 million, or 17%, for the three months ended March 31, 2003 compared to the same period in 2002. The decrease was due to a $6 million decrease in Generation's equity earnings in Sithe, primarily due to Sithe's sale of Exelon New England to Generation in November 2002. This decrease was partially offset by a $2 million increase in Generation's equity earnings of AmerGen.

Other, Net
Other, Net decreased $183 million for the three months ended March 31, 2003 compared to the same period in 2002. This decrease is primarily a result of the $200 million impairment charge related to Generation's equity investment in Sithe due to an other than temporary decline in value. This charge was partially offset by higher investment income related to the decommissioning trust funds.

Income Taxes
The effective income tax rate was 28.8% for the three months ended March 31, 2003 compared to 40.5% for the same period in 2002. The decrease was primarily attributed to the impact of the impairment of Generation's investment in Sithe and other tax benefits recorded in 2003.

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

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

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

LIQUIDITY AND CAPITAL RESOURCES

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

Cash Flows from Operating Activities

Cash flows provided by operations were $278 million for the three months ended March 31, 2003, compared to $509 million for the same period in 2002. The decrease in cash flows from operating activities was primarily attributable to a $184 million decrease in working capital. Generation's cash flows from operating activities primarily result from the sale of electric energy to wholesale customers, including Generation's affiliated companies, as well as settlements arising from Generation's trading activities. Generation's future cash flow from operating activities will depend upon future demand and market prices for energy and the ability to continue to produce and supply power at competitive costs.

Cash Flows from Investing Activities

Cash flows used in investing activities were $216 million for the three months ended March 31, 2003, compared to $379 million for the same period in 2002. The decrease in cash flows used in investing activities was primarily attributable to a decrease in capital expenditures. Capital expenditures decreased $70 million related to liquidated damages from Raytheon (see Note 8 of the Condensed Combined Notes to Consolidated Financial Statements). The liquidated damages were partially offset by a $58 million increase in expenditures related to the plants acquired after the first quarter of 2002. Nuclear fuel expenditures decreased due to two refueling outages that occurred during the three months ended March 31, 2003 compared to four outages in the same period in the prior year. Generation's proposed capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.

Generation's capital expenditures for 2003 reflect the construction of three Exelon New England generating facilities with projected capacity of 2,421 MWs of energy and additions to

and upgrades of existing facilities (including nuclear refueling outages) and nuclear fuel. In February 2002, Generation entered into an agreement to loan AmerGen up to $75 million at an interest rate of one-month LIBOR plus 2.25%. In July 2002, the loan agreement and the loan were increased to $100 million and the maturity date was extended to July 1, 2003. As of March 31, 2003, the balance of the loan to AmerGen was $35 million. 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 $63 million for the three months ended March 31, 2003, compared to cash flows provided by financing activities of $1 million for the same period in 2002. The increase in cash used in financing was primarily due to a $56 million increase in restricted cash as a result of liquidating damage proceeds received from Raytheon in 2003 (see Note 8 of the Condensed Combined Notes to Consolidated Financial Statements).

Credit Issues

Generation meets its short-term liquidity requirements primarily through intercompany borrowings from Exelon, the issuance of commercial paper and participation in the intercompany money pool. Generation, along with Exelon, ComEd and PECO, participates in a $1.5 billion unsecured 364-day revolving credit facility with a group of banks. The credit facility became effective on November 22, 2002 and includes a term-out option that allows any outstanding borrowings at the end of the revolving credit period to be repaid on November 21, 2004. Exelon may increase or decrease the sublimits of each of the participants upon written notification to these banks. As of March 31, 2003, there was no sublimit for Generation. The credit facility is expected to be used by Generation principally to support its commercial paper program.

The credit facility requires Generation to maintain a cash from operations to interest expense ratio for the twelve-month period ended on the last day of any quarter. The ratio excludes certain changes in working capital, revenues from Exelon New England and interest on the debt of Exelon New England's project subsidiaries. Generation's threshold for the ratio reflected in the credit agreement cannot be less than 3.25 to 1 for the twelve-month period ended March 31, 2003. At March 31, 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 and its subsidiary Commonwealth Edison of Indiana, Inc., PECO, Generation and Business Services Company may participate in the money pool as lenders and borrowers, and Exelon 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, although Exelon is not permitted to be a net borrower from the money pool. Interest on borrowings is based on short-term market rates of interest, or specific borrowing rates if the funds are provided by external financing. During the first quarter 2003, Generation had various

borrowings from ComEd under the money pool. The maximum amount of loans outstanding at any time during the quarter was $335 million. As of March 31, 2003, there were no outstanding loan balances.

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

Under PUHCA, Generation can only pay dividends from undistributed or current earnings. Generation is precluded from lending or extending credit or indemnity to Exelon. At March 31, 2003, Generation had undistributed earnings of $980 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 March 31, 2003 were materially unchanged from the amounts set forth in the 2002 Form 10-K except for the following:

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