Exelon Corp · 8-K · For 2/28/02 · EX-99

Filed On 3/7/02   ·   SEC File 1-16169   ·   Accession Number 950159-2-144

Current Report   ·   Form 8-K
Filing Table of Contents

Document/Exhibit                   Description                      Pages   Size 

 1: 8-K         Current Report                                         3     10K 
 2: EX-23       Consent of Experts or Counsel                          1      6K 
 3: EX-99       Exhibit 99.1                                           2     11K 
 4: EX-99       Exhibit 99.2                                           2     10K 
 5: EX-99       Exhibit 99.3                                          27    185K 
 6: EX-99       Exhibit 99.4                                          43    281K 

EX-99   ·   Exhibit 99.3

EX-99
1st Page of 27
TOC
Top
Previous
Next
Bottom
Just 1st
 
Sponsored Ads...


Exhibit 99-3                                                                    

 Exelon Corporation and Subsidiary Companies
 Management's Discussion and Analysis of Financial Condition and
 Results of Operations

EX-99
2nd Page of 27
TOC
1st
Previous
Next
Bottom
Just 2nd

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL                               
CONDITION AND RESULTS OF OPERATIONS                                             
Exelon Corporation and Subsidiary Companies                                     

General                                                                         

On October 20, 2000, Exelon  Corporation  (Exelon) became the parent corporation
for each of PECO Energy Company (PECO) and  Commonwealth  Edison Company (ComEd)
as a result of the completion of the  transactions  contemplated by an Agreement
and Plan of Exchange  and Merger,  as amended,  among PECO,  Unicom  Corporation
(Unicom) and Exelon  (Merger).  The Merger was  accounted for using the purchase
method of accounting.  Exelon's  results of operations for 1999 and 2000 consist
of PECO's  results  of  operations  for 1999 and 2000 and  Unicom's  results  of
operations after October 20, 2000.                                              
     During  January  2001,  Exelon  undertook a  restructuring  to separate its
generation and other  competitive  businesses from its regulated energy delivery
business at ComEd and PECO. As part of the restructuring, the generation-related
operations  and  assets and  liabilities  of ComEd  were  transferred  to Exelon
Generation Company,  LLC (Generation).  Also, as part of the restructuring,  the
non-regulated   operations   and  related   assets  and   liabilities  of  PECO,
representing   PECO's  Generation  and  Enterprises   business  segments,   were
transferred to Generation and Exelon  Enterprises  Company,  LLC  (Enterprises),
respectively.  Additionally,  certain  operations and assets and  liabilities of
ComEd and PECO were transferred to Exelon Business Services Company.            

Exelon, through its subsidiaries, operates in three business segments:          

-    Energy  Delivery,  consisting of the retail  electricity  distribution  and
     transmission   businesses  of  ComEd  in  northern  Illinois  and  PECO  in
     southeastern Pennsylvania and the natural gas distribution business of PECO
in the Pennsylvania counties surrounding the City of Philadelphia.    
-    Generation,  consisting of electric generating facilities, energy marketing
     operations and equity interests in Sithe Energies, Inc. (Sithe) and AmerGen
Energy Company, LLC (AmerGen).                                        
-    Enterprises,  consisting of  competitive  retail  energy sales,  energy and
     infrastructure  services,  communications  and other  investments  weighted
     towards the communications, energy services and retail services industries.

See Note 21 of the  Notes  to  Consolidated  Financial  Statements  for  further
segment information.                                                            

Results of Operations                                                           

Year Ended December 31, 2001 Compared To Year Ended December 31, 2000           

Net Income and Earnings Per Share                                               
Exelon's net income increased $842 million,  or 144%, for 2001. Diluted earnings
per share increased $1.56 per share, or 54%. Income before  extraordinary  items
and  cumulative  effect of  changes  in  accounting  principles  increased  $850
million,  or 150%,  for  2001.  Diluted  earnings  per  share on the same  basis
increased  $1.62 per share,  or 58%.  Earnings per share increased less than net
income as a result of an increase in the weighted average shares of common stock
outstanding  from the  issuance of common stock in  connection  with the Merger,
partially offset by the repurchase of common stock with the proceeds from PECO's
May 2000 stranded cost recovery securitization.                                 

Earnings Before Interest and Income Taxes                                       
Exelon  evaluates the  performance  of its business  segments  based on earnings
before interest and income taxes (EBIT).  In addition to components of operating
income as shown on the consolidated  statements of income,  EBIT includes equity
in earnings (losses) of unconsolidated  affiliates, and other income and expense
recorded in other,  net,  with the  exception of  investment  income.  Operating
revenues, operating expenses, depreciation and amortization and other income and
expenses  for  each  business   segment  in  the  following   analyses   include
intercompany  transactions,  which are  eliminated  in the  consolidated  Exelon
financial statements.                                                           

1 

EX-99
3rd Page of 27
TOC
1st
Previous
Next
Bottom
Just 3rd

     The  October  20,  2000  acquisition  of  Unicom,  and the  January 1, 2001
corporate restructuring,  significantly impacted Exelon's results of operations.
To  provide a more  meaningful  analysis  of  results  of  operations,  the EBIT
analyses by business  segment  below  identify the portion of the EBIT  variance
that is  attributable  to Unicom's  results of operations and the portion of the
variance  that  results  from  normal  operations  attributable  to  changes  in
components  of  the  underlying   operations  of  Exelon.  The  merger  variance
represents  Unicom  results for 2000 prior to the  October 20, 2000  acquisition
date as well as the effect of excluding  Merger-related costs from Exelon's 2000
operations.  The segment  results also  reflect the results as if the  corporate
restructuring  occurred  on January 1, 2000.  The 2000 pro forma  effects of the
Merger and  restructuring  were  developed  using  estimates  of various  items,
including   allocation   of  corporate   overheads  to  business   segments  and
intercompany transactions.                                                      

                                                        [Enlarge/Download Table]

EBIT Contribution by Business Segment                                                                        
                                                                                       Components of Variance
                                                                                   --------------------------
                                                                                     Merger            Normal
(in millions)                           2001             2000       Variance       Variance        Operations
-------------------------------------------------------------------------------------------------------------
                                                                                                             
Energy Delivery                      $  2,623        $  1,503      $   1,120        $  1,219      $    (99)  
Generation                                962             440            522              22           500   
Enterprises                              (107)           (140)            33             (32)           65   
Corporate                                 (22)           (328)           306             286            20   
-----------------------------------------------------------------------------------------------------------  
EBIT                                 $   3,456       $  1,475      $   1,981        $  1,495      $    486   
===========================================================================================================  

                                                        [Enlarge/Download Table]

Energy Delivery                                                                                             
                                                                                      Components of Variance
                                                                                   -------------------------
                                                                                      Merger          Normal
(in millions)                             2001           2000       Variance        Variance      Operations
------------------------------------------------------------------------------------------------------------
                                                                                                            
Operating Revenue                    $  10,171       $  4,511      $   5,660        $  5,168      $    492  
Operating Expense and Other              6,467          2,711          3,756           3,242           514  
Depreciation & Amortization              1,081            297            784             707            77  
----------------------------------------------------------------------------------------------------------- 
EBIT                                 $   2,623       $  1,503      $   1,120        $  1,219      $    (99) 
=========================================================================================================== 

Energy  Delivery's  EBIT increased  $1,120 million in 2001, as compared to 2000.
The Merger  accounted for $1,219 million of the variance offset by a decrease in
EBIT from normal  operations  of $99  million.  The decrease in EBIT from normal
operations reflects increased operating and maintenance  expenses and regulatory
asset  amortization,  partially  offset  by  improved  margins  on sales  due to
favorable rate changes.                                                         
     Energy  Delivery's  operating  and  maintenance  expenses  increased due to
higher  administrative and general costs as a result of increased  allocation of
costs previously  recorded at Corporate,  and $18 million for employee severance
costs  associated  with the Merger,  partially  offset by a decrease in customer
costs.  Higher  purchased power costs for 2001 include charges for energy losses
incurred during  distribution from Generation (line loss charges),  however line
loss charges were not included in the 2000 pro forma purchased power costs.     
     Other  expenses  increased $73 million due primarily to a $113 million gain
on a ComEd  forward share  repurchase  arrangement  recognized  during the first
quarter of 2000,  partially  offset by a $38 million  non-recurring  loss on the
sale of Cotter  Corporation,  a ComEd  subsidiary,  recognized  during the first
quarter of 2000.                                                                
     Depreciation and amortization  increased $77 million  reflecting  increased
regulatory  asset   amortization  of  $34  million  consistent  with  regulatory
provisions,   and  increased  depreciation  expense  of  $43  million  primarily
associated with capital additions.                                              
     Depreciation  and  amortization  includes  goodwill  amortization  of  $126
million  in 2001,  which  will be  discontinued  in 2002  upon the  adoption  of
Financial  Accounting  Standards Board (FASB) Statement of Financial  Accounting
Standards (SFAS) No. 142 "Goodwill and Other Intangible  Assets" (SFAS No. 142).

2 

EX-99
4th Page of 27
TOC
1st
Previous
Next
Bottom
Just 4th

Energy Delivery's electric sales statistics are as follows:                     

                                                        [Enlarge/Download Table]

Deliveries (in megawatthours (MWh))                          2001                 2000(a)         Variance  
------------------------------------------------------------------------------------------------------------
                                                                                                            
Residential                                            36,459,606           35,307,675           1,151,931  
Small Commercial & Industrial                          37,183,693           36,506,400             677,293  
Large Commercial & Industrial                          36,824,787           39,663,127          (2,838,340) 
Public Authorities & Electric Railroads                10,003,853            9,828,668             175,185  
------------------------------------------------------------------------------------------------------------
Total Retail Deliveries                               120,471,939          121,305,870            (833,931) 
============================================================================================================

The table above includes  deliveries of 16 million MWhs in 2001 to customers who
purchase energy from alternative suppliers.                                     

                                                        [Enlarge/Download Table]

Electric Revenue (in millions)                            2001               2000(a)            Variance    
------------------------------------------------------------------------------------------------------------
                                                                                                            
Residential                                         $       3,571        $       3,483       $          88  
Small Commercial & Industrial                               2,852                2,680                 172  
Large Commercial & Industrial                               1,933                1,796                 137  
Public Authorities & Electric Railroads                       568                  544                  24  
------------------------------------------------------------------------------------------------------------
Total Electric Retail Revenue                               8,924                8,503                 421  
------------------------------------------------------------------------------------------------------------
Wholesale and Miscellaneous Revenue                           593                  643                 (50) 
------------------------------------------------------------------------------------------------------------
Total Electric Revenue                              $       9,517        $       9,146       $         371  
============================================================================================================
<FN>                                                                                                        
 (a) Includes the operations of ComEd as if the Merger occurred on January 1, 2000.                         
</FN>                                                                                                       

The changes in electric retail revenues for 2001, as compared to 2000, as if the
Merger occurred on January 1, 2000, are attributable to the following:          

                                                        [Enlarge/Download Table]

(in millions)                                                                                    Variance   
------------------------------------------------------------------------------------------------------------
                                                                                                            
Rate Changes                                                                                 $         217  
Customer Choice                                                                                        131  
Weather                                                                                                 98  
Revenue Taxes                                                                                          (88) 
Other Effects                                                                                           63  
------------------------------------------------------------------------------------------------------------
Electric Retail Revenue                                                                      $         421  
============================================================================================================

-    Rate  Changes.  The  increase  in  revenues  attributable  to rate  changes
     reflects  the  expiration  of a 6% reduction  in PECO's  electric  rates in
     effect  for 2000  related  to PECO's  restructuring  settlement,  partially
     offset by a $60 million PECO rate  reduction  in effect for 2001,  and a 5%
     ComEd residential rate reduction,  effective  October 1, 2001,  required by
the Illinois restructuring legislation.                               
-    Customer  Choice.  ComEd  non-residential  customers and all PECO customers
     have the choice to  purchase  energy  from  other  suppliers.  This  choice
     generally does not impact kWh  deliveries,  but affects  revenue  collected
     from customers related to energy supplied by Energy Delivery. The favorable
     customer  choice  effect is  attributable  to  increased  revenues  of $276
     million from  customers in  Pennsylvania  selecting or returning to PECO as
     their  electric  generation  supplier,  partially  offset by a decrease  in
     revenues of $145  million from  customers in Illinois  electing to purchase
     energy from an alternative  retail  electric  supplier  (ARES) or the power
     purchase option (PPO),  under which customers can purchase power from ComEd
     at a market-based  rate.  Exelon continues to collect delivery charges from
these customers.                                                      
-    Weather. The demand for electricity and gas services 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 and gas.
     Conversely,  mild weather reduces demand.  Although weather was moderate in
     2001,  the  weather  impact was  favorable  compared to the prior year as a
     result of warmer summer  weather offset in part by warmer winter weather in
2001, primarily in the ComEd service territory.                       

3 

EX-99
5th Page of 27
TOC
1st
Previous
Next
Bottom
Just 5th

-    Revenue  taxes.  The  change  in  revenue  taxes  represents  a  change  in
     presentation  of certain  revenue  taxes  from  operating  revenue  and tax
     expense to  collections  recorded as  liabilities  resulting  from Illinois
legislation. This change in presentation does not affect income.      
-    Other  Effects.  A  strong  housing  construction  market  in  Chicago  has
     contributed to  residential  and small  commercial and industrial  customer
     volume  growth,  partially  offset  by the  unfavorable  impact of a slower
economy on large commercial and industrial customers.                 

     The reduction in Wholesale and Miscellaneous  revenues in 2001, as compared
to 2000,  reflects  lower  off-system  sales due to the  expiration of wholesale
contracts  that were  offered by ComEd from June 2000 to May 2001 to support the
open access  program in Illinois,  partially  offset by  increased  transmission
service revenue and the reversal of a $15 million reserve for revenue refunds to
ComEd's municipal customers as a result of a favorable Federal Energy Regulatory
Commission (FERC) ruling.                                                       

Energy Delivery's gas sales statistics are as follows:                          

                                                        [Enlarge/Download Table]

                                                                     2001          2000           Variance 
-----------------------------------------------------------------------------------------------------------
                                                                                                           
Deliveries in million cubic feet (mmcf)                            81,528        91,686            (10,158)
Revenue (in millions)                                                $654          $532               $122 
-----------------------------------------------------------------------------------------------------------

The changes in gas revenue for 2001, as compared to 2000, are as follows:       

                                                        [Enlarge/Download Table]

(in millions)                                                                                     Variance 
-----------------------------------------------------------------------------------------------------------
                                                                                                           
Price                                                                                             $    174 
Weather                                                                                                (38)
Volume                                                                                                 (14)
-----------------------------------------------------------------------------------------------------------
Gas Revenue                                                                                       $    122 
===========================================================================================================

-    Price. The favorable  variance in price is attributable to an adjustment of
     the  purchased  gas  cost  recovery  by  the  Pennsylvania  Public  Utility
     Commission  (PUC) effective in December 2000. The average price per million
     cubic feet for all customers for 2001 was 39% higher than 2000.  PECO's gas
     rates are subject to periodic adjustments by the PUC designed to recover or
     refund 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.                      
-    Weather.   The  unfavorable   weather  impact  is  attributable  to  warmer
     temperatures  in the  non-summer  months  of 2001  than in 2000 in the PECO
     service  territory.  Heating  degree days decreased 12% in 2001 compared to
2000.                                                                 
-    Volume.  Exclusive  of weather  impacts,  lower  delivery  volume  affected
     revenue  by $14  million  compared  to 2000.  Total  mmcf  sales to  retail
     customers  decreased 11% compared to 2000,  primarily as a result of slower
economic conditions in 2001 offset by customer growth.                

Generation                                                                      

                                                        [Enlarge/Download Table]

                                                                                    Components of Variance  
                                                                                  --------------------------
                                                                                    Merger          Normal  
(in millions)                           2001            2000       Variance       Variance      Operations  
------------------------------------------------------------------------------------------------------------
                                                                                                            
Operating Revenue                    $ 7,048        $  3,316       $  3,732        $ 2,772            $960  
Operating Expense and Other            5,804           2,750          3,054          2,667             387  
Depreciation & Amortization              282             126            156             83              73  
------------------------------------------------------------------------------------------------------------
EBIT                                 $   962        $    440       $    522        $    22            $500  
============================================================================================================

4 

EX-99
6th Page of 27
TOC
1st
Previous
Next
Bottom
Just 6th

Generation's  EBIT  increased $522 million for 2001 compared to 2000. The Merger
accounted for $22 million of the variance.  The remaining $500 million  increase
resulted primarily from higher margins on market and affiliate  wholesale energy
sales,  coupled with decreased operating costs at the nuclear plants,  partially
offset by additional depreciation and amortization. During the first five months
of 2001,  Generation  benefited  from  increases  in  wholesale  market  prices,
particularly   in  the   Pennsylvania-New   Jersey-Maryland   control  area  and
Mid-America  Interconnected  Network  regions.  The increase in wholesale market
prices was primarily driven by significant  increases in fossil fuel prices. The
large  concentration of nuclear  generation in the Generation  portfolio allowed
Exelon to  capture  the  higher  prices  in the  wholesale  market  for sales to
non-affiliates  with minimal  increase in fuel prices.  Generation  revenues for
2001 include  charges to affiliates for line losses.  Line loss charges were not
included  in pro forma 2000  revenue.  Generation  also  benefited  from  higher
nuclear  plant  output due to increased  capacity  factors  during 2001.  Energy
marketing activities positively impacted 2001 results. Mark-to-market gains were
$16  million  and $14  million on  non-trading  and  trading  energy  contracts,
respectively,  offset by realized trading losses of $6 million.  Lower operating
costs are  attributable  to  reductions  in the  number of  employees  and fewer
nuclear  outages in 2001 than in 2000,  which  offset the effect of increases in
reserves related to litigation of $30 million.  In addition,  Generation's  EBIT
benefited  from an  increase  in equity in  earnings of AmerGen and Sithe of $90
million in 2001 compared to the prior year period as a result of acquisitions in
2000. The increase in depreciation and amortization  expense primarily  reflects
an  increase  in   decommissioning   expense  of  $140  million  reflecting  the
discontinuance of regulatory accounting practices for certain nuclear generating
stations,  partially  offset by a $90  million  reduction  in  depreciation  and
decommissioning expense attributable to the extension of estimated service lives
of Generation's generating plants.                                              

For 2001, Generation's sales were 201,879 GWhs,  approximately 60% of which were
to affiliates. Supply sources were as follows:                                  

                                                        [Enlarge/Download Table]

-----------------------------------------------------------------------------------------------------------
                                                                                                           
Nuclear units                                                                                          54% 
Purchases                                                                                              37% 
Fossil and hydro units                                                                                  3% 
Generation investments                                                                                  6% 
-----------------------------------------------------------------------------------------------------------
Total                                                                                                 100% 
===========================================================================================================

Generation's nuclear fleet,  including AmerGen,  performed at a weighted average
capacity  factor  of 94.4%  for  2001  compared  to 93.8% in 2000.  Generation's
nuclear fleet's  production costs,  including  AmerGen,  were $12.79 per MWh for
2001, compared to $14.65 per MWh for 2000.                                      

Enterprises                                                                     

                                                        [Enlarge/Download Table]

                                                                                    Components of Variance 
                                                                                ---------------------------
                                                                                   Merger           Normal 
(in millions)                         2001            2000        Variance       Variance       Operations 
-----------------------------------------------------------------------------------------------------------
                                                                                                           
Operating Revenue                  $ 2,292         $ 1,395         $   897        $   467         $   430  
Operating Expense and Other          2,330           1,500             830            491             339  
Depreciation & Amortization             69              35              34              8              26  
-----------------------------------------------------------------------------------------------------------
EBIT                               $  (107)        $  (140)        $    33        $   (32)        $    65  
===========================================================================================================

Enterprises'  EBIT  increased  $33  million for 2001  compared  to 2000.  Normal
operations  contributed $65 million of the variance,  which was partially offset
by a $32 million reduction attributable to the Merger. The increase in EBIT from
normal  operations  primarily  reflects  $27  million of net  realized  gains on
investments, $23 million from lower net losses in communications joint ventures,
$21 million of reduced losses on the sale of assets,  and $15 million  primarily
from improved margins and reduced  operating  expenses of retail energy sales in
Pennsylvania.  These  increases  were  partially  offset by $13  million  of net
writedowns on investments.                                                      

5 

EX-99
7th Page of 27
TOC
1st
Previous
Next
Bottom
Just 7th

     Enterprises'  revenues  increased  $897 million for 2001  compared to 2000.
Normal  operations  contributed  $430 million and the Merger added $467 million.
Operating revenues attributable to normal operations increased $574 million as a
result  of  acquisitions  by its  services  businesses.  Additionally,  revenues
increased by $26 million as a result of increased operations at Exelon Services.
These increases were partially  offset by $166 million lower revenues  primarily
attributable to reduced operations of retail energy sales in Pennsylvania.      
     Enterprises'  operating and other expenses  increased $830 million for 2001
compared to 2000.  Normal  operations  contributed  $339  million and the Merger
added $491  million.  Operating  expenses from normal  operations  included $554
million  as  a  result  of  acquisitions   made  by  its  services   businesses.
Additionally,  operating  and  other  expenses  increased  by $32  million  from
increased operations at Exelon Services and $13 million due to net writedowns on
investments.  These  increases were partially  offset by $193 million from lower
expense primarily  attributable to reduced  operations of retail energy sales in
Pennsylvania,  $27 million from net realized gains on  investments,  $23 million
from lower net  losses in  communications  joint  ventures,  and $21  million of
reduced losses on the sale of assets.                                           
     Enterprises' depreciation and amortization expense increased primarily as a
result of goodwill  amortization  related to  acquisitions  made by its services
businesses.                                                                     
     Depreciation and amortization includes goodwill amortization of $24 million
in 2001, which will be discontinued in 2002 upon the adoption of SFAS No. 142.  
     Enterprises'   investments   are  weighted   towards   investments  in  the
communication  industry,  which  continues  to  be  adversely  impacted  by  the
significant downturn in the communications market.                              

Other Components of Net Income                                                  
Interest Charges Interest charges consist of interest expense and  distributions
on  preferred  securities  of  subsidiaries.  Interest  charges  increased  $524
million,  or 83%,  for 2001.  The increase was  primarily  attributable  to $438
million from the effects of the Merger,  $70 million  related to  borrowings  by
Exelon to finance the Merger cash consideration and the December 2000 investment
in  Sithe as well as  additional  interest  of $16  million  as a result  of the
issuance  of  transition  bonds in May 2000 to  securitize  a portion  of PECO's
stranded cost recovery.                                                         

Investment   Income   Investment  income  is  recorded  in  Other,  Net  on  the
Consolidated  Statements of Income, but is excluded from EBIT. Investment income
decreased  by $17  million  due to net  realized  losses of $60  million  on the
nuclear  decommissioning  trust funds for the nuclear stations formerly owned by
ComEd,  offset by increased income of $43 million,  primarily  reflecting a full
year of  investment  income from the former Unicom  companies,  as well as money
market  interest and  interest on the loan to Sithe  recorded at  Generation  in
2001.                                                                           

Income Taxes Income taxes increased by $590 million in 2001 as compared to 2000,
$541  million of which is due to higher  pretax  income and $49 million due to a
higher  effective  income  tax  rate.  The  increase  in income  taxes  reflects
additional  pretax  income  of  $1,440  million,  of  which  $1,044  million  is
attributable to the Merger.  The effective income tax rate was 39.7% for 2001 as
compared to 37.6% for 2000.  The increase in the  effective  income tax rate was
primarily attributable to goodwill amortization associated with the Merger which
is not deductible for tax purposes, a higher effective state income tax rate due
to operations in Illinois subsequent to the Merger, reduced impact of investment
tax credit amortization and a favorable annual tax return adjustment recorded in
2001.                                                                           

Extraordinary Items In 2000, Exelon incurred  extraordinary  charges aggregating
$6 million ($4  million,  net of tax)  related to  prepayment  premiums  and the
write-off of unamortized  deferred  financing  costs  associated  with the early
retirement  of debt with a portion of the proceeds  from the  securitization  of
PECO's stranded cost recovery in May 2000.                                      

Cumulative Effect of Changes in Accounting Principles On January 1, 2001, Exelon
adopted  SFAS  No.  133  "Accounting  for  Derivative  Instruments  and  Hedging
Activities"  (SFAS No. 133),  as amended,  resulting in a benefit of $20 million
($12  million,  net of income  taxes).  On January 1,  2000,  Exelon  recorded a
benefit of $40 million  ($24  million,  net of income  taxes)  representing  the
cumulative  effect of a change in accounting  method for nuclear outage costs by
PECO  in  conjunction  with  the   synchronization  of  accounting  policies  in
connection with the Merger.                                                     

6 

EX-99
8th Page of 27
TOC
1st
Previous
Next
Bottom
Just 8th

Year Ended December 31, 2000 Compared To Year Ended December 31, 1999           

Net Income and Earnings Per Share                                               
Exelon's net income increased $16 million,  or 3% in 2000.  Diluted earnings per
share were  consistent with the prior year period.  Income before  extraordinary
items and cumulative effect of a change in accounting  principle,  decreased $41
million,  or 7% in 2000.  Diluted  earnings  per  share on the same  basis  were
consistent  with the prior period.  Earnings per share  increased  less than net
income  because of an increase in the  weighted  average  shares of common stock
outstanding  as a result of the issuance of common stock in connection  with the
Merger,  partially  offset by the  repurchase  of common stock with the proceeds
from PECO's March 1999 and May 2000 stranded cost recovery securitizations.     

Earnings Before Interest and Income Taxes To provide a more meaningful  analysis
of results of operations,  the EBIT analyses by business  segment below identify
the portion of the EBIT variance  that is  attributable  to Unicom's  results of
operations  and the portion of the variance that results from normal  operations
attributable  to changes in components of the  underlying  operations of Exelon.
The merger  variance  represents  the former Unicom  companies'  results for the
period  after the Merger on October 20, 2000 as well as the effect of  excluding
Merger-related  costs from Exelon's 2000  operations.  The 2000 and 1999 results
also  reflect the  corporate  restructuring  as if it had occurred on January 1,
1999. The 2000 pro forma effects of the Merger and restructuring  were developed
using estimates of various items, including allocation of corporate overheads to
business segments and intercompany transactions.                                

                                                        [Enlarge/Download Table]

EBIT Contribution by Business Segment                                                                      

                                                                                    Components of Variance 
                                                                                ---------------------------
                                                                                    Merger          Normal 
(in millions)                           2000          1999       Variance         Variance      Operations 
-----------------------------------------------------------------------------------------------------------
                                                                                                           
Energy Delivery                      $ 1,503      $  1,372       $    131          $   297        $   (166)
Generation                               440           379             61               34              27 
Enterprises                             (140)         (212)            72               (4)             76 
Corporate                               (328)         (194)          (134)            (272)            138 
-----------------------------------------------------------------------------------------------------------
Total                                $ 1,475      $  1,345       $    130          $    55        $     75 
===========================================================================================================

                                                        [Enlarge/Download Table]

Energy Delivery                                                                                            
                                                                                    Components of Variance 
                                                                                ---------------------------
                                                                                    Merger          Normal 
(in millions)                           2000          1999       Variance         Variance      Operations 
-----------------------------------------------------------------------------------------------------------
                                                                                                           
Operating Revenue                    $ 4,511      $  3,265       $  1,246          $ 1,138        $    108 
Operating Expense and Other            2,711         1,785            926              739             187 
Depreciation & Amortization              297           108            189              102              87 
-----------------------------------------------------------------------------------------------------------
EBIT                                 $ 1,503      $  1,372       $    131          $   297        $   (166)
===========================================================================================================

Energy  Delivery's EBIT increased $131 million in 2000, as compared to 1999. The
Merger  accounted for $297 million of the variance  offset by a decrease in EBIT
from  normal  operations  of $166  million.  The  decrease  in EBIT from  normal
operations reflects increased operating and maintenance  expenses and regulatory
asset amortization which more than offset the increase in revenue.  The increase
in revenue from normal  operations is attributable to improved  margins on sales
due to customers in  Pennsylvania  selecting PECO as their  electric  generation
supplier and rate adjustments partially offset by lower summer volume.          
     Energy  Delivery's  operating  expenses and other  increased  due to higher
administrative  and general  costs as a result of increased  allocation of costs
previously  recorded at Corporate,  partially  offset by a nonrecurring  capital
stock credit related to a 1999  adjustment  associated with the impact of PECO's
1997 restructuring charge.                                                      
     Depreciation and amortization  increased $87 million  primarily  reflecting
increased regulatory asset amortization consistent with regulatory orders.      

7 

EX-99
9th Page of 27
TOC
1st
Previous
Next
Bottom
Just 9th

                                                        [Enlarge/Download Table]

Generation                                                                                                 
                                                                                    Components of Variance 
                                                                                ---------------------------
                                                                                    Merger          Normal 
(in millions)                           2000          1999       Variance         Variance      Operations 
-----------------------------------------------------------------------------------------------------------
                                                                                                           
Operating Revenue                    $ 3,316      $  2,411       $    905          $   590        $    315 
Operating Expense and Other            2,750         1,907            843              528             315 
Depreciation & Amortization              126           125              1               28             (27)
-----------------------------------------------------------------------------------------------------------
EBIT                                 $   440      $    379       $     61          $    34        $     27 
===========================================================================================================

Generation's  EBIT  increased $61 million for 2000 compared to 1999.  The Merger
accounted  for $34 million of the variance.  The remaining $27 million  increase
resulted primarily from higher margins on market and affiliate  wholesale energy
sales and from the abandonment of two  information  systems  implementations  in
1999 and a $15 million  write-off in 1999 of the  investment  in a  cogeneration
facility  in  connection  with  the  settlement  of  litigation.   In  addition,
Generation's  EBIT also  benefited  from an  increase  in equity in  earnings of
AmerGen of $4 million in 2000 compared to the prior year period.  Effective with
the  acquisition  of Clinton  Nuclear  Power Station  (Clinton) by AmerGen,  the
management agreement for Clinton was terminated,  resulting in lower revenues of
$99 million and lower operation and maintenance expense of $70 million.         
     Generation's  nuclear  fleet,  including  AmerGen,  performed at a weighted
average capacity factor of 93.8% for 2000. Generation's nuclear fleet production
costs for 2000 were $14.65 per MWh.                                             

                                                        [Enlarge/Download Table]

Enterprises                                                                                                
                                                                                    Components of Variance 
                                                                                ---------------------------
                                                                                    Merger          Normal 
(in millions)                           2000          1999       Variance         Variance      Operations 
-----------------------------------------------------------------------------------------------------------
                                                                                                           
Operating Revenue                    $ 1,395      $    644       $    751          $   277        $    474 
Operating Expense and Other            1,500           852            648              278             370 
Depreciation & Amortization               35             4             31                3              28 
-----------------------------------------------------------------------------------------------------------
EBIT                                 $  (140)     $   (212)      $     72          $    (4)       $     76 
===========================================================================================================

Enterprises'  EBIT  increased  $72  million for 2000  compared  to 1999.  Normal
operations  contributed $76 million of the variance,  which was partially offset
by a $4 million reduction  attributable to the Merger. The increase in EBIT from
normal  operations  primarily  reflects a reduction in losses from retail energy
sales partially offset by writedowns on communications investments and losses in
communications joint ventures.                                                  
     Enterprises'  revenues  increased  $751 million for 2000  compared to 1999.
Normal  operations  contributed  $474 million and the Merger added $277 million.
Operating revenues attributable to normal operations increased $530 million as a
result of thirteen  infrastructure  services  company  acquisitions  in 2000 and
1999, partially offset by reduced retail energy sales.                          
     Enterprises'  operating and other expenses  increased $648 million for 2000
compared to 1999.  Normal  operations  contributed  $370  million and the Merger
added  $278  million.   Increased  operating  expenses  from  normal  operations
primarily related to the thirteen  infrastructure  services company acquisitions
and to  writedowns on  communication  investments  and losses in  communications
joint ventures, partially offset by reduced retail energy sales.                
     Enterprises' depreciation and amortization expense increased primarily as a
result  of  goodwill   amortization  related  to  its  infrastructure   services
businesses acquisitions.                                                        

Other Components of Net Income                                                  
Interest  Charges  Interest  charges  increased  $203  million,  or 47%, to $632
million in 2000.  The increase was primarily  attributable  to $156 million from
the  operations  of Unicom  since the Merger and interest of $104 million on the
transition bonds issued to securitize  PECO's stranded cost recovery,  partially
offset by $77 million of lower interest  charges as a result of the reduction of
PECO's long-term debt with the proceeds from the securitization.                

8 

EX-99
10th Page of 27
TOC
1st
Previous
Next
Bottom
Just 10th

Investment   Income   Investment  income  is  recorded  in  Other,  Net  on  the
Consolidated  Statements of Income, but is excluded from EBIT. Investment income
increased  by $12  million to $64  million  in 2000,  primarily  reflecting  the
effects of the Merger.                                                          

Income  Taxes The  effective  tax rate was 37.6% in 2000 as compared to 37.1% in
1999.                                                                           

Extraordinary Items In 2000, Exelon incurred  extraordinary  charges aggregating
$6 million ($4  million,  net of tax)  related to  prepayment  premiums  and the
write-off of unamortized  deferred  financing  costs  associated  with the early
retirement  of debt with a portion of the proceeds  from the  securitization  of
PECO's stranded cost recovery in May 2000.                                      
     In 1999, Exelon incurred extraordinary charges aggregating $62 million ($37
million,  net of tax)  related  to  prepayment  premiums  and the  write-off  of
unamortized debt costs associated with the repayment and refinancing of debt.   

Cumulative Effect of a Change in Accounting Principle In 2000, Exelon recorded a
benefit of $40 million  ($24  million,  net of income  taxes)  representing  the
cumulative  effect of a change in accounting  method for nuclear outage costs by
PECO  in  conjunction  with  the   synchronization  of  accounting  policies  in
connection with the Merger.                                                     

Liquidity and Capital Resources                                                 

Exelon'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.  Exelon's  access to external  financing at
reasonable  terms  is  dependent  on  the  credit  ratings  of  Exelon  and  its
subsidiaries  and the general  business  condition  of Exelon and the  industry.
Exelon's businesses are capital intensive.  Capital resources are used primarily
to fund Exelon's capital requirements,  including  construction,  investments in
new and existing ventures,  repayments of maturing debt and preferred securities
of  subsidiaries  and payment of common stock  dividends.  Any potential  future
acquisitions could require external financing,  including the issuance by Exelon
of common stock.                                                                

Cash Flows from Operating Activities                                            
Cash flows  provided by  operations  for 2001 were $3.6  billion,  approximately
two-thirds of which were provided by Energy  Delivery and one-third of which was
provided by Generation.  Enterprises' cash flows from operations were immaterial
to Exelon  in 2001.  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.  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.                  

9 

EX-99
11th Page of 27
TOC
1st
Previous
Next
Bottom
Just 11th

Cash Flows from Investing  Activities                                           
Cash flows used in investing  activities  for 2001 were $2.4 billion,  primarily
for capital  expenditures  of $2.0  billion.  Capital  expenditures  by business
segment for 2001 and projected amounts for 2002 are as follows:                 

                                                        [Enlarge/Download Table]

(in millions)                                                                       2001              2002 
-----------------------------------------------------------------------------------------------------------
                                                                                                           
Energy Delivery                                                                 $  1,133         $   1,060 
Generation                                                                           803             1,089 
Enterprises                                                                           70               114 
Corporate and Other                                                                   35                27 
-----------------------------------------------------------------------------------------------------------
Subtotal                                                                        $  2,041         $   2,290 
TXU Acquisition                                                                       --               443 
-----------------------------------------------------------------------------------------------------------
Total Capital Expenditures and TXU Acquisition                                  $  2,041         $   2,733 
===========================================================================================================

Energy  Delivery's   estimated   capital   expenditures  for  2002  reflect  the
continuation of efforts to further  improve the reliability of its  distribution
system  in  the  Chicago  region.   Approximately   36%  of  the  budgeted  2002
expenditures  are for growth and the  remainder  for additions to or upgrades of
existing  facilities.  Exelon  anticipates  that  Energy  Delivery  will  obtain
financing,  when  necessary,  through  borrowings,  the  issuance  of  preferred
securities, or capital contributions from Exelon.                               
     Approximately 75% of Generation's  estimated capital  expenditures for 2002
are for  additions to and  upgrades of existing  facilities  (including  nuclear
refueling  outages),  nuclear fuel and increases in capacity at existing plants.
Capital  expenditures  are projected to increase in 2002 as compared to 2001 due
to higher  nuclear  fuel  expenditures,  growth and an increase in the number of
planned  refueling  outages,   during  which  significant  maintenance  work  is
performed.  Eleven nuclear refueling outages, including AmerGen, are planned for
2002,  compared  to six during  2001.  Total  capital  expenditures  for nuclear
refueling  outages are  expected  to increase in 2002 over 2001 by $24  million.
Exelon has committed to provide AmerGen with capital contributions equivalent to
50% of the purchase  price of any  acquisitions  AmerGen  makes in 2002.  Exelon
anticipates that Generation's  capital expenditures will be funded by internally
generated funds,  Generation borrowings or capital contributions from Exelon. In
addition to the 2002 capital expenditures of $1.1 billion, Generation expects to
close the purchase of two natural-gas and oil-fired  plants from TXU Corp. (TXU)
in the first quarter of 2002. The $443 million purchase is expected to be funded
with available cash and commercial paper.                                       
     Enterprises'  capital  expenditures were $70 million in 2001.  Enterprises'
estimated  capital   expenditures  for  2002  are  approximately  $114  million,
primarily  for  additions  to  or  upgrades  of  existing  facilities.   All  of
Enterprises'  investments are expected to be funded by capital  contributions or
borrowings from Exelon.                                                         
     Exelon's total estimated  capital  expenditures  in 2002 are  approximately
$2.7 billion including the acquisition of the TXU generating stations.  Exelon'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  were $1.3  billion in 2001  primarily
attributable  to debt service and payments of  dividends on common  stock.  Debt
financing activities during 2001 were as follows:                               

-    Exelon  Corporation  - Retired a $1.2 billion term loan with  proceeds from
     $500 million and $700 million senior unsecured note issuances at Exelon and
Generation, respectively.                                             
-    Energy Delivery - Refinanced $805 million in PECO transition bonds, retired
     $340  million of ComEd  transitional  trust  notes and early  retired  $196
million in First Mortgage Bonds with available cash.                  
-    Generation - Issued $121 million of pollution control bonds to refinance an
     equivalent  amount  originally  issued by PECO and issued  $700  million of
senior unsecured notes.                                               

10

EX-99
12th Page of 27
TOC
1st
Previous
Next
Bottom
Just 12th

The 2001 common stock  dividend  payments of $583 million  cover the period from
October 20, 2000, the date of the Merger,  through November 15, 2001. On January
29,  2002,  the Board of Directors  of Exelon  declared a quarterly  dividend of
$0.44 per share of  Exelon's  common  stock.  This  increase  of $0.07 per share
annually,  will result in an annual  dividend  rate of $1.76 per share.  The new
dividend rate reflects Exelon's vertically integrated business portfolio and its
focus on total return to shareholders.  The new dividend rate represents about a
50% payout of the  expected  2002  earnings  per share from  Exelon's  regulated
electricity delivery businesses.  Exelon intends to grow the dividend to about a
60% payout of earnings from regulated operations based on cash flow and earnings
growth prospects for Energy Delivery. The payment of future dividends is subject
to approval and declaration by the Board of Directors each quarter.             

Credit  Issues                                                                  
Exelon  meets  its  short-term  liquidity  requirements  primarily  through  the
issuance  of  commercial  paper by Exelon,  ComEd and PECO.  Exelon,  along with
ComEd,  PECO and  Generation,  entered into a $1.5 billion  unsecured  revolving
credit facility with a group of banks.  Generation currently cannot borrow under
the credit agreement until it has delivered audited financial  statements to the
banks,  which is  expected  to occur in the first  quarter of 2002.  This credit
facility is used  principally to support the commercial paper program of Exelon,
ComEd and PECO.                                                                 
     At December 31, 2001,  Exelon had outstanding $360 million of notes payable
consisting  principally of commercial paper. For 2001, the average interest rate
on notes payable was  approximately  2.63%.  Certain of the credit agreements to
which Exelon,  ComEd,  PECO and Generation  are parties  require each of them to
maintain  a debt  to  total  capitalization  ratio  of 65%  or  less,  excluding
securitization debt (and for PECO, excluding the receivable from parent recorded
in  PECO's  shareholders'  equity).  At  December  31,  2001,  the debt to total
capitalization  ratios on that basis for Exelon, ComEd, PECO and Generation were
47%, 45%, 38% and 26%, respectively.                                            
     Exelon and its subsidiaries'  access to the capital markets,  including the
commercial  paper  market,  and  their  financing  costs  in those  markets  are
dependent  on their  respective  securities  ratings.  None of  Exelon's  or its
subsidiaries'  borrowings  are subject to default or prepayment as a result of a
downgrading  of securities  ratings  although such a downgrading  could increase
interest   charges  under  Exelon's  bank  credit   facility.   Exelon  and  its
subsidiaries  from  time to  time  enter  into  interest  rate  swap  and  other
derivatives 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.             
     Exelon has obtained an order from the  Securities  and Exchange  Commission
(SEC) under the Public Utility Holding  Company Act of 1935 (PUHCA)  authorizing
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 December 31, 2001, $3.0 billion of financing authority
is  available  under  the SEC  order.  Exelon  requested,  and the SEC  reserved
jurisdiction over, an additional $4 billion in financing  authorization.  Exelon
agreed to limit its short-term debt  outstanding to $3 billion of the $4 billion
total financing authority.  Exelon has asked the SEC to eliminate the short-term
debt restriction. The SEC order also authorized Exelon to issue guarantees of up
to $4.5 billion  outstanding  at any one time. At December 31, 2001,  Exelon had
provided $1.4 billion of guarantees.  See Contractual Obligations and Commercial
Commitments in this section.  The SEC order requires  Exelon 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 December 31, 2001,  Exelon's common
equity to total capitalization was 35%.                                         
     Under PUHCA and the Federal Power Act, Exelon,  ComEd,  PECO and Generation
can pay dividends only from retained or current earnings. However, the SEC order
granted  permission  to Exelon and ComEd to pay up to $500  million in dividends
out of  additional  paid-in  capital,  provided  that  Exelon  agreed not to pay
dividends out of paid-in capital after December 31, 2002 if its common equity is
less than 30% of its total  capitalization.  At December  31,  2001,  Exelon had
retained  earnings of $1.2 billion,  which includes  ComEd retained  earnings of
$257 million,  PECO retained  earnings of $270 million and  Generation  retained
earnings of $471 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).  Exelon requested,  and the SEC reserved
jurisdiction over, an additional $1.5 billion in EWGs and FUCOs.                
     During 2001, Exelon loaned Sithe $150 million, which was repaid by Sithe in
December of 2001 from the proceeds of a bank borrowing.  In connection with that
bank borrowing, Exelon provided the lenders with a support letter confirming its
investment  in Sithe and Exelon's  agreement to maintain a positive net worth of
Sithe.  Sithe's  net worth is  expected to remain  positive  for the  forseeable
future  and  accordingly  this  agreement  is not  reflected  in  the  following
Contractual                                                                     

11

EX-99
13th Page of 27
TOC
1st
Previous
Next
Bottom
Just 13th

Obligations  and  Commercial  Commitments  discussion.  This  agreement does not
guarantee  any debt or obligation  of Sithe.  During 2001,  Sithe paid Exelon $2
million in interest on the loan.                                                

Contractual Obligations and Commercial Commitments                              
Exelon's  contractual  obligations  as of December  31, 2001  representing  cash
obligations that are considered to be firm commitments are as follows:          

                                                        [Enlarge/Download Table]

                                                                          Payment due within                
                                                    ----------------------------------------     Due after  
(in millions)                           Total         1 Year     2-3 Years         4-5 Years       5 Years  
------------------------------------------------------------------------------------------------------------
                                                                                                            
Long-Term Debt                       $  14,411      $  1,406      $  2,287          $  2,576       $ 8,142  
Short-Term Debt                            360           360            --                --            --  
Operating Leases                           990            82           152               128           628  
Purchase Obligations                    12,192         1,695         3,173             1,346         5,978  
Spent Nuclear Fuel Obligation              843            --            --                --           843  
Acquisition of TXU Generating                                                                               
   Stations                                443           443            --                --            --  
------------------------------------------------------------------------------------------------------------
Total Contractual Obligations        $  29,239      $  3,986      $  5,612          $  4,050       $15,591  
============================================================================================================

For additional information about                                                
     - long-term  debt  see  Note  14 of the  Notes  to  Consolidated  Financial
Statements                                                        
     - short-term  debt  see  Note 13 of the  Notes  to  Consolidated  Financial
Statements                                                        
     - operating  leases  see  Note 20 of the  Notes to  Consolidated  Financial
Statements                                                        
     - purchase  obligations see Note 20 of the Notes to Consolidated  Financial
Statements                                                        
     - the TXU acquisition  see Note 20 of the Notes to  Consolidated  Financial
Statements                                                        
     - the  spent  nuclear  fuel   obligation  see  Note  12  of  the  Notes  to
Consolidated Financial Statements                                 

Exelon has an obligation  to  decommission  its nuclear  power plants.  Exelon's
current estimate of  decommissioning  costs for its owned nuclear plants is $7.2
billion in current year (2002) dollars.  Nuclear decommissioning activity occurs
primarily  after the plants  retirement  and is currently  estimated to begin in
2045. At December 31, 2001 the decommissioning liability, which is recorded over
the life of the plant, recorded in Accumulated Depreciation and Deferred Credits
and Other Liabilities on Exelon's  Consolidated  Balance Sheets was $2.7 billion
and $1.3 billion,  respectively.  In order to fund future decommissioning costs,
Exelon held $3.2  billion of  investments  in trust funds which are  included as
Investments in Exelon's  Consolidated  Balance Sheets and include net unrealized
and realized gains.                                                             
     Exelon's  commercial  commitments  as of  December  31,  2001  representing
commitments triggered by future events, including obligations to make payment on
behalf of other parties as well as financing  arrangements to secure obligations
of Exelon, are as follows:                                                      

                                                        [Enlarge/Download Table]

                                                                           Expiration within                
                                                     ---------------------------------------         After  
(in millions)                               Total     1 Year     2-3 Years         4-5 Years       5 Years  
------------------------------------------------------------------------------------------------------------
                                                                                                            
Available Lines of Credit (a)          $    1,500    $ 1,500       $    --          $     --      $     --  
Letters of Credit (non-debt) (b)               38         37             1                --            --  
Letters of Credit (Long-Term Debt) (c)        427        122           305                --            --  
Insured Long-Term Debt (d)                    154         --           154                --            --  
Guarantees (e)                              1,410        218           310                --           882  
------------------------------------------------------------------------------------------------------------
Total Commercial Commitments           $    3,529    $ 1,877       $   770          $     --      $    882  
============================================================================================================
<FN>                                                                                                        
(a)  Lines of Credit - Exelon,  along with ComEd,  PECO,  and  Generation,  maintain a $1.5 billion  364-day
     credit facility to support  commercial paper  issuances.  At December 31, 2001, there are no borrowings
     against the credit facility.  Additionally,  at December 31, 2001, there was $360 million of commercial
     paper outstanding.                                                                                     
(b)  Letters of Credit  (non-debt) - Exelon and certain of its  subsidiaries  maintain  non-debt  letters of
     credit to provide credit support for certain transactions as requested by third parties.               
(c)  Letters  of  Credit  (Long-Term  Debt) -  Direct-pay  letters  of  credit  issued  in  connection  with
     variable-rate  debt in order to provide  liquidity in the event that it is not possible to remarket all
     of the debt as required  following  specific events,  including changes in the basis of determining the
     interest rate on the debt.                                                                             
(d)  Insured  Long-Term Debt - Borrowings that have been  credit-enhanced  through the purchase of insurance
     coverage equal to the amount of principal outstanding plus interest.                                   
(e)  Guarantees - Provide support for lines of credit, performance contracts, surety bonds, energy marketing
     contracts, nuclear insurance, and leases as required by third parties.                                 
</FN>                                                                                                       

12

EX-99
14th Page of 27
TOC
1st
Previous
Next
Bottom
Just 14th

Off Balance Sheet Obligations                                                   
Generation  owns  49.9% of the  outstanding  common  stock  of Sithe  and has an
option,  beginning on December 18, 2002, to purchase the remaining  common stock
outstanding  (Remaining  Interest)  in Sithe.  The  purchase  option  expires on
December 18, 2005. In addition,  the Sithe stockholders who own in the aggregate
the  Remaining  Interest  have the right to require  Generation  to purchase the
Remaining  Interest (Put Rights) during the same period in which  Generation can
exercise its purchase option.  At the end of this exercise period, if Generation
has not exercised its purchase option and the other Sithe  stockholders have not
exercised their Put Rights,  Generation will have an additional  one-time option
to purchase shares from the other  stockholders  in Sithe to bring  Generation's
ownership in Sithe from the current 49.9% to 50.1% of Sithe's total  outstanding
common stock.                                                                   
     If Generation exercises its option to acquire the Remaining Interest, or if
all the other Sithe  stockholders  exercise their Put Rights, the purchase price
for 70% of the Remaining  Interest will be set at fair market value subject to a
floor  of $430  million  and a  ceiling  of $650  million.  The  balance  of the
Remaining  Interest will be valued at fair market value without being subject to
floor or ceiling  prices.  In either  instance,  interest  shall accrue from the
beginning of the exercise period.                                               
     If Generation increases its ownership in Sithe to 50.1% or more, Sithe will
become a  consolidated  subsidiary and Exelon's  financial  results will include
Sithe's financial results from the date of purchase. At December 31, 2001, Sithe
had total assets of $4.2 billion and long-term  debt of $2.3 billion,  including
$2.1  billion of  non-recourse  project  debt,  and  excluding  $107  million of
non-recourse  project debt associated with Sithe's equity  investments.  For the
year ended  December 31, 2001 Sithe had  revenues of $1 billion.  As of December
31, 2001 Exelon had a $725 million equity investment in Sithe.                  
     Additionally,  the debt on the  books  of  Exelon's  unconsolidated  equity
investments and joint ventures is not reflected on Exelon's Consolidated Balance
Sheets.  Total  investee  debt,  including  the debt of Sithe  described  in the
preceding  paragraph,  is currently  estimated to be $2.4 billion  ($1.2 billion
based on Exelon's ownership interest of the investments).                       
     Generation  and  British  Energy,  Generation's  joint  venture  partner in
AmerGen,  have each agreed to provide up to $100  million to AmerGen at any time
for operating expenses.                                                         

Other Factors                                                                   

In 2001, Exelon adopted a cash balance pension plan. All management and electing
union  employees  who  joined  Exelon or one of its  participating  subsidiaries
during 2001  became  participants  in the plan.  Management  employees  who were
active  participants  in Exelon's  previous  qualified  defined benefit plans at
December  31, 2000 and are employed by Exelon on January 1, 2002 will be given a
choice to convert to the cash  balance  plan.  Participants  in the cash balance
plan,  unlike  participants  in the other defined  benefit plans,  may request a
lump-sum  cash payment upon employee  termination  which may result in increased
cash requirements  from pension plan assets.  Exelon may be required to increase
future  funding  to the  pension  plan  as a  result  of  these  increased  cash
requirements.                                                                   
     Due to the  performance  of the United  States  debt and equity  markets in
2001,  the value of assets held in trusts to satisfy the  obligations of pension
and  postretirement  benefit plans and the eventual nuclear  generating  station
decommissioning  has  decreased.  Also,  as a result of the Merger and corporate
restructuring,  there  was a larger  than  average  number of  employees  taking
advantage  of  retirement  benefits  in 2001.  These  factors may also result in
additional future funding requirements of the pension and postretirement benefit
plans.  Contributions to the nuclear decommissioning trust funds of $112 million
offset  net  losses  of  $109  million,  resulting  in  a  2%  increase  in  the
decommissioning  trust funds  balance at December 31, 2001  compared to December
31, 2000.  Exelon  believes  that the amounts  being  recovered  from  customers
through  electric  rates  along  with the  earnings  on the trust  funds will be
sufficient to fund its decommissioning  obligations.  For additional information
about nuclear  decommissioning  see Notes 1 and 12 of the Notes to  Consolidated
Financial Statements.                                                           

13

EX-99
15th Page of 27
TOC
1st
Previous
Next
Bottom
Just 15th

Quantitative and Qualitative Disclosures About Market Risk                      

Exelon is exposed to market  risks  associated  with  commodity  price,  credit,
interest  rates  and  equity  prices.  The  inherent  risk in  market  sensitive
instruments  and positions is the potential loss arising from adverse changes in
commodity  prices,  counterparty  credit,  interest  rates and  equity  security
prices.  Exelon's  corporate  Risk  Management  Committee  (RMC) sets forth risk
management philosophy and objectives through a corporate policy, and establishes
procedures  for risk  assessment,  control and  valuation,  counterparty  credit
approval,  and the  monitoring  and  reporting of  derivative  activity and risk
exposures.  The RMC is chaired by Exelon's  chief risk  officer and includes the
chief financial officer, general counsel, treasurer, vice president of corporate
planning and officers  from each of the business  units.  The RMC reports to the
board of directors on the scope of Exelon's derivative activities.              

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

Marketing  (non-trading)  activities To the extent Exelon's  generation  supply,
(either  owned or  contracted)  is in excess of its  obligations  to  customers,
including ComEd and PECO's retail load, that available  electricity is sold into
the  wholesale  markets.  To reduce  price risk  caused by market  fluctuations,
Exelon enters into derivative contracts, including forwards, futures, swaps, and
options with approved  counterparties to hedge Exelon's  anticipated  exposures.
Market  price  risk  exposure  is the risk of a change in the value of  unhedged
positions.  Exelon expects to maintain a minimum 80% hedge ratio in 2002 for its
energy  marketing  portfolio.  This hedge ratio  represents  the  percentage  of
Exelon's forecasted aggregate annual generation supply that is committed to firm
sales,  including sales to Energy Delivery's retail load. The hedge ratio is not
fixed and will vary from time to time depending upon market  conditions,  demand
and  volatility.  Absent any  opportunistic  efforts to  mitigate  market  price
exposure,  the estimated  market price  exposure for the  non-trading  portfolio
associated with a ten percent reduction in the average  around-the-clock  market
price of electricity is an approximate $100 million  decrease in net income,  or
approximately $0.30 per share. This sensitivity,  which is consistent with prior
guidance,  assumes an 80% hedge  ratio,  and that  price  changes  occur  evenly
throughout  the year and across all  markets.  The  sensitivity  also  assumes a
static  portfolio.  Exelon expects to actively  manage its portfolio to mitigate
the market price exposure. Actual results could differ depending on the specific
timing of, and markets affected by, the price changes, as well as future changes
in Exelon's portfolio.                                                          

Trading activities Exelon began to use financial  contracts for trading purposes
in the second  quarter of 2001.  The trading  activities  were entered into as a
complement to Exelon's energy  marketing  portfolio and represent a very limited
portion of Exelon's overall energy marketing activities.  For example, the limit
on open positions in electricity  for any forward month  represents less than 5%
of the owned and  contracted  supply of  electricity.  The trading  portfolio is
planned to grow modestly in 2002,  subject to stringent risk  management  limits
and policies,  including volume,  stop-loss and  value-at-risk  limits to manage
exposure  to market  risk.  A  value-at-risk  (VAR)  model is used to assess the
market risk associated with financial  derivative  instruments  entered into for
trading  purposes.  VAR represents the potential gains or losses for instruments
or portfolios due to changes in market factors,  for a specified time period and
confidence  level. The measured VAR as of December 31, 2001, using a Monte Carlo
model with a 95%  confidence  level and  assuming  a one-day  time  horizon  was
approximately $800,000. The measured VAR represents an estimate of the potential
change in value of Exelon's  portfolio of trading related  financial  derivative
instruments.  These estimates, however, are not necessarily indicative of actual
results,  which may differ due to the fact that actual market rate  fluctuations
may differ from forecasted  fluctuations  and due to the fact that the portfolio
may change over the holding period.                                             

14

EX-99
16th Page of 27
TOC
1st
Previous
Next
Bottom
Just 16th

     Exelon's  energy  contracts  are  accounted  for under SFAS No.  133.  Most
non-trading contracts qualify for a normal purchases and normal sales exception.
Those that do not are recorded as assets or  liabilities on the balance sheet at
fair value. Changes in the fair value of qualifying hedge contracts are recorded
in Other  Comprehensive  Income, and gains and losses are recognized in earnings
when the underlying  transaction occurs. Changes in the fair value of derivative
contracts that do not meet hedge criteria under SFAS No. 133 and the ineffective
portion of hedge  contracts  are  recognized  in  earnings  on a current  basis.
Outlined  below is a summary of the  changes  in fair value for those  contracts
included as assets and  liabilities  in the  Consolidated  Balance Sheet for the
year ended December 31, 2001:                                                   

                                                        [Enlarge/Download Table]

(in millions)                                                                      Non-trading        Trading
-------------------------------------------------------------------------------------------------------------
                                                                                                             
Fair value of contracts outstanding as of January 1, 2001                                                    
  (reflects the adoption of SFAS No. 133)                                          $       (7)     $      -  
    Change in fair value during 2001:                                                                        
       Contracts settled during year                                                       87             7  
       Mark-to-market gain/(loss)                                                          (2)            7  
------------------------------------------------------------------------------------------------------------ 
    Total change in fair value                                                             85            14  
------------------------------------------------------------------------------------------------------------ 
Fair value of contracts outstanding at December 31, 2001                           $       78      $     14  
============================================================================================================ 

The total change in fair value  during 2001 is  reflected in the 2001  financial
statements as follows:                                                          

                                                        [Enlarge/Download Table]

                                                                                  Non-trading        Trading
------------------------------------------------------------------------------------------------------------
                                                                                                            
Mark-to-market gain/(loss) on non-qualifying hedge contracts or                                             
    hedge ineffectiveness reflected in earnings                                    $       16      $     14 
Mark-to-market gain/(loss) on hedge contracts reflected in                                                  
    Other Comprehensive Income                                                             69            -- 
------------------------------------------------------------------------------------------------------------
Total change in fair value                                                         $       85      $     14 
============================================================================================================

The majority of Exelon's  contracts are  non-exchange  traded  contracts  valued
using prices  provided by external  sources,  which  primarily  represent  price
quotations  available through brokers or  over-the-counter,  on-line  exchanges.
Prices  reflect the average of the bid-ask  midpoint  prices  obtained  from all
sources that Exelon  believes  provide the most liquid market for the commodity.
The terms for which such price information is available varies by commodity,  by
region and by product. The remainder of the assets represent contracts for which
external  valuations  are  not  available,  primarily  option  contracts.  These
contracts  are  valued  using the  Black  model,  an  industry  standard  option
valuation model and other valuation techniques. The fair values in each category
reflect the level of forward  prices and  volatility  factors as of December 31,
2001 and may  change  as a result  of  future  changes  in  these  factors.  The
maturities of the net energy trading and non-trading  assets and sources of fair
value as of December 31, 2001 are as follows:                                   

                                                        [Enlarge/Download Table]

                                                                               Maturities within             
                                                            ------------------------------------   Total Fair
(in millions)                                                  1 Year     2-3 Years    4-5 Years        Value
-------------------------------------------------------------------------------------------------------------
                                                                                                             
Non-trading:                                                                                                 
Actively quoted prices                                      $      --    $       --   $      --   $      --  
Prices provided by other external sources                          36            50          --          86  
Prices based on model or other valuation methods                   (4)            2          (6)         (8) 
------------------------------------------------------------------------------------------------------------ 
  Total                                                     $      32    $       52   $      (6)  $      78  
============================================================================================================ 

Trading:                                                                                                     
Actively quoted prices                                      $      --    $       --   $      --   $      --  
Prices provided by other external sources                          10             4          --          14  
Prices based on model or other valuation methods                   --            --          --          --  
------------------------------------------------------------------------------------------------------------ 
  Total                                                     $      10    $        4   $      --   $      14  
============================================================================================================ 

15

EX-99
17th Page of 27
TOC
1st
Previous
Next
Bottom
Just 17th

Management  uses its best estimates to determine the fair value of commodity and
derivative  contracts  it holds and  sells.  These  estimates  consider  various
factors including closing exchange and over-the-counter  price quotations,  time
value,  volatility  factors,  and credit exposure.  However, it is possible that
future  market  prices  could  vary from  those  used in  recording  assets  and
liabilities  from energy marketing and trading  activities,  and such variations
could be material.                                                              

Credit Risk                                                                     
ComEd and PECO are each obligated to provide  service to all electric  customers
within their respective franchised territories. As a result, ComEd and PECO each
have a broad customer  base.  For the year ended December 31, 2001,  ComEd's ten
largest customers  represented  approximately 3% of its retail electric revenues
and PECO's ten largest  customers  represented  approximately  10% of its retail
electric revenues.  Credit risk for Energy Delivery is managed by each company's
credit and  collection  policies,  which are  consistent  with state  regulatory
requirements.                                                                   
     Generation has credit risk associated with  counterparty  performance which
includes  but is not limited to the risk of financial  default or slow  payment.
Counterparty  credit risk is managed  through  established  policies,  including
establishing  counterparty credit limits, and in some cases,  requiring deposits
and  letters  of credit to be posted  by  certain  counterparties.  Generation's
counterparty credit limits are based on a scoring model that considers a variety
of factors,  including leverage,  liquidity,  profitability,  credit ratings and
risk  management  capabilities.  Generation  has  entered  into  master  netting
agreements with the majority of its large counterparties,  which reduce exposure
to risk by  providing  for the  offset of amounts  payable  to the  counterparty
against the counterparty receivables.                                           
     Generation participates in the five established,  real-time energy markets,
which are administered by independent system operators (ISOs): Pennsylvania, New
Jersey,  Maryland,  LLC (PJM), which is in the Mid-Atlantic Area Council region:
New England and New York,  which are both in the  Northeast  Power  Coordinating
Council region, California, which is in the Western Systems Coordinating Council
region and Texas, which is administered by the Electric  Reliability  Council of
Texas.  Approximately one-half of Generation's  transactions,  on a megawatthour
basis,  were made in these  markets.  In these  areas,  power is traded  through
bilateral  agreements  between  buyers and sellers and on the spot markets which
are operated by the ISOs. In areas where there is no spot market, electricity is
purchased and sold solely through bilateral agreements.  For sales into the spot
markets administered by the ISOs, the ISO maintains financial assurance policies
that are established and enforced by those  administrators.  The credit policies
of the ISO's may under certain  circumstances  require that losses  arising from
the default of one member on spot market transactions be shared by the remaining
participants.  Non-performance  or  non-payment by a major  counterparty,  could
result in a material adverse impact on Exelon's financial condition,  results of
operations or net cash flows.                                                   
     Exelon's  balance sheet  includes a $427 million net investment in a direct
financing  lease as of December 31, 2001.  The  investment  in direct  financing
leases  represents  future  minimum lease  payments due at the end of the thirty
year  life of the  lease of  $1,492  million,  less  unearned  income  of $1,065
million.  The future  minimum lease  payments are  supported by  collateral  and
credit enhancement measures including letters of credit, surety bonds and credit
swaps issued by high credit quality financial institutions.                     

Interest Rate Risk                                                              
Exelon  uses a  combination  of fixed  rate and  variable  rate  debt to  reduce
interest rate exposure.  Interest rate swaps may be used to adjust exposure when
deemed   appropriate  based  upon  market   conditions.   Exelon  also  utilizes
forward-starting interest rate swaps and treasury rate locks to lock in interest
rate levels in anticipation of future  financing.  These strategies are employed
to maintain the lowest cost of capital.  As of December 31, 2001, a hypothetical
10% increase in the interest  rates  associated  with  variable  rate debt would
result in an $1 million decrease in pre-tax earnings for 2002.                  
     Exelon  has  entered  into  interest  rate  swaps to manage  interest  rate
exposure  associated with the floating rate series of transition bonds issued to
securitize  PECO's  stranded  cost  recovery and with a $235 million  fixed-rate
obligation of ComEd.  In December  2001,  Exelon  entered into  forward-starting
interest  rate  swaps,  with an  aggregate  notional  amount of $250  million in
anticipation  of the issuance of debt at ComEd in the first  quarter of 2002. At
December 31, 2001,  these interest rate swaps had an aggregate fair market value
exposure  of $21  million  based on the  present  value  difference  between the
contract and market rates at December 31, 2001.                                 

16

EX-99
18th Page of 27
TOC
1st
Previous
Next
Bottom
Just 18th

     The  aggregate  fair value  exposure of the interest  rate swaps that would
have resulted from a  hypothetical  50 basis point decrease in the spot yield at
December  31,  2001  is  estimated  to  be  $34  million.  If  these  derivative
instruments  had been terminated at December 31, 2001, this estimated fair value
represents the amount that would be paid by Exelon to the counterparties.       
     The  aggregate  fair value  exposure of the interest  rate swaps that would
have resulted from a  hypothetical  50 basis point increase in the spot yield at
December  31,  2001  is  estimated  to  be  $11  million.  If  these  derivative
instruments  had been terminated at December 31, 2001, this estimated fair value
represents the amount to be paid by Exelon to the counterparties.               

Equity Price Risk                                                               
Exelon maintains trust funds, as required by the Nuclear  Regulatory  Commission
(NRC),  to fund  certain  costs of  decommissioning  its nuclear  plants.  As of
December  31,  2001,  these  funds  are  reflected  at fair  value  on  Exelon's
Consolidated  Balance  Sheets.  The mix of  securities  is  designed  to provide
returns to be used to fund  decommissioning  and to compensate for  inflationary
increases in decommissioning costs. However, the equity securities in the trusts
are  exposed to price  fluctuations  in equity  markets,  and the value of fixed
rate, fixed income  securities are exposed to changes in interest rates.  Exelon
actively  monitors the investment  performance  and  periodically  reviews asset
allocation  in  accordance  with  Exelon's  nuclear  decommissioning  trust fund
investment policy. A hypothetical 10% increase in interest rates and decrease in
equity prices would result in a $204 million  reduction in the fair value of the
trust assets.                                                                   

Critical Accounting Policies                                                    

The preparation of financial  statements in conformity  with Generally  Accepted
Accounting  Principles  requires that management apply  accounting  policies and
make  estimates  and  assumptions  that  affect  results of  operations  and the
reported  amounts of assets and  liabilities  in the financial  statements.  The
following  areas  represent  those that  management  believes  are  particularly
important to the financial  statements and that require the use of estimates and
assumptions to describe matters that are inherently uncertain:                  

Accounting for Derivative Instruments                                           
Exelon uses derivative financial  instruments  primarily to manage its commodity
price and interest rate risks.  Derivative  financial  instruments are accounted
for under SFAS No. 133.  Accounting for derivatives  continues to evolve through
guidance issued by the Derivatives  Implementation  Group (DIG) of the Financial
Accounting Standards Board. To the extent that changes by the DIG modify current
guidance,  including the normal  purchases and normal sales  determination,  the
accounting treatment for derivatives may change.                                

Energy Contracts To manage its utilization of generation supply (including owned
and  contracted  assets),  Exelon  enters  into  contracts  to  purchase or sell
electricity,  fossil fuels, and ancillary  products such as transmission  rights
and  congestion  credits,  and  emission  allowances.   These  energy  marketing
contracts are considered  derivatives  under SFAS 133 unless a determination  is
made that they  qualify  for a SFAS No. 133 normal  purchases  and normal  sales
exclusion.  If the exclusion applies,  those contracts are not  marked-to-market
and are not reflected in the financial statements until delivery occurs.        
     The  availability  of the normal  purchases  and normal sales  exclusion to
specific  contracts  is based  on a  determination  that  excess  generation  is
available for a forward sale and similarly a determination that at certain times
generation  supply will be  insufficient to serve load.  This  determination  is
based on internal models that forecast  customer  demand and generation  supply.
The models include  assumptions  regarding customer load growth rates, which are
influenced  by the  economy,  weather  and the impact of  customer  choice,  and
generating unit  availability,  particularly  nuclear generating unit capability
factors.  The critical assumptions used in the determination of normal purchases
and normal sales are consistent with assumptions  used in the general  corporate
planning process.                                                               

17

EX-99
19th Page of 27
TOC
1st
Previous
Next
Bottom
Just 19th

     Energy  contracts  that are  considered  derivatives  may be  eligible  for
designation as hedges. If a contract is designated as a hedge, the change in its
market value is generally deferred as a component of other comprehensive  income
until the transaction it is hedging is completed.  Conversely, the change in the
market  value of  derivatives  not  designated  as hedges is recorded in current
period earnings.  To qualify as a cash flow hedge, the fair value changes in the
derivative  must be expected to offset  80%-120% of the changes in fair value or
cash  flows  of  the  hedged  item.  The  effectiveness  of an  energy  contract
designated  as a hedge  is  determined  by  internal  models  that  measure  the
statistical correlation between the derivative and the associated hedged item.  
     When external  quoted market prices are not available,  Exelon utilizes the
Black model, a standard industry  valuation model to determine the fair value of
energy  derivative   contracts  marked  to  market.  The  valuation  model  uses
volatility assumptions relating to future energy prices based on specific energy
markets and utilizes externally available forward market price curves.          

Interest Rate Derivatives Exelon utilizes  derivatives to manage its exposure to
fluctuation  in  interest  rates  related  to  outstanding  variable  rate  debt
instruments  and planned future debt issuances as well as exposure to changes in
the fair value of outstanding debt that is planned for early  retirement.  Hedge
accounting  is used  for all  interest  rate  derivatives  to date  based on the
probability of the transaction and the expected highly  effective  nature of the
hedging  relationship  between the interest  rate swap contract and the interest
payment or changes in fair value of the hedged debt. Dealer quotes are available
for all of Exelon's interest rate swap agreement derivatives.                   

Regulatory  Assets and  Liabilities                                             
Regulatory assets represent  incurred costs that have been deferred because they
are  probable  of future  recovery  in customer  rates.  Regulatory  liabilities
represent  previous  collections from customers to fund costs which have not yet
been incurred.                                                                  
     Both ComEd and PECO are  currently  subject to rate  freezes that limit the
opportunity  to  recover  increased  costs  and the costs of new  investment  in
facilities  through rates during the rate freeze  period.  Current rates include
the recovery of Exelon's existing regulatory assets. Exelon continually assesses
whether the  regulatory  assets are probable of future  recovery by  considering
factors such as applicable regulatory environment changes, recent rate orders to
other regulated entities in the same jurisdiction, and the status of any pending
or potential deregulation legislation.  If future recovery of costs ceases to be
probable  the assets  would be  required  to be  recognized  in  current  period
earnings.                                                                       

Nuclear Decommissioning                                                         
Exelon's current  estimate of its nuclear  facilities'  decommissioning  cost is
$7.2 billion in current year (2002) dollars.  Calculating this estimate involves
significant   assumptions   with   respect   to  the   expected   increases   in
decommissioning  costs  relative  to  general  inflation  rates,  changes in the
regulatory   environment   or  regulatory   requirements,   and  the  timing  of
decommissioning.  The  estimated  service life of the nuclear  station is also a
significant  assumption because  decommissioning  costs are generally recognized
over the life of the  generating  station.  Cost  estimates for  decommissioning
Exelon's  nuclear  facilities  have been prepared by an independent  engineering
firm and  reflect  currently  existing  regulatory  requirements  and  available
technology.  Nuclear station service lives, over which the decommissioning costs
are recognized, were extended by 20 years in 2001. The life extension is subject
to NRC  approval of an  extension  of existing  NRC  operating  licenses,  which
generally are 40 years. The obligation for  decommissioning  currently operating
plants  is  recorded  in  accumulated   depreciation  consistent  with  industry
practice. As discussed in New Accounting Pronouncements, this accounting will be
affected by the adoption of SFAS No. 143, "Asset Retirement  Obligations"  (SFAS
No.  143)  effective  January  1,  2003.  See Notes 1 and 12 of the Notes to the
Consolidated   Financial  Statements  for  further  information   regarding  the
accounting for decommissioning.                                                 

18

EX-99
20th Page of 27
TOC
1st
Previous
Next
Bottom
Just 20th

Unbilled Energy Revenues                                                        
Revenues  related to the sale of energy are  generally  recorded when service is
rendered or energy is delivered to customers.  However, the determination of the
energy  sales to  individual  customers  is based on the reading of their meters
which are read on a systematic  basis  throughout the month.  At the end of each
month, amounts of energy delivered to customers since the date of the last meter
reading are estimated and the corresponding unbilled revenue is estimated.  This
unbilled  revenue is  estimated  each month based on daily  generation  volumes,
estimated  customer usage by class,  line losses and  applicable  customer rates
based on  regression  analyses  reflecting  significant  historical  trends  and
experience.  Customer  accounts  receivable  as of  December  31,  2001  include
unbilled energy revenues of $361 million.                                       

Contract Accounting                                                             
Enterprises  recognizes  contract  revenue  and  profits  on  certain  long-term
fixed-price contracts by the  percentage-of-completion  method of accounting. In
determining  the amount of revenue to  recognize  Exelon is required to estimate
the total costs and profits  expected to be recorded under the contract over its
contract term, and the recoverability of costs related to change orders. Changes
in these estimates could result in the recognition of differences in earnings.  

Environmental Costs                                                             
As of  December  31, 2001 Exelon had  accrued  liabilities  of $156  million for
environmental  investigation  and remediation  costs.  The liabilities are based
upon  estimates  with  respect to the number of sites for which  Exelon  will be
responsible,  the  scope  and cost of work to be  performed  at each  site,  the
portion of costs that will be shared  with other  parties  and the timing of the
remediation  work.  Where  timing and  amounts of  expenditures  can be reliably
estimated,  amounts are discounted.  Where timing and amounts cannot be reliably
estimated, a range is estimated and the low end of the range is recognized on an
undiscounted  basis.  Estimates  can be  affected  by factors  including  future
changes  in  technology,   changes  in  regulations  or  requirements  of  local
governmental authorities and actual costs of disposal.                          

Outlook                                                                         

Changes in the Utility Industry                                                 
The electric utility industry in the United States remains in transition.  It is
moving from a fully  regulated  industry,  consisting  primarily  of  integrated
companies combining  generation,  transmission and distribution,  to competitive
wholesale  generation  markets with continuing  regulation of  transmission  and
distribution.   The  transition  has  resulted  in  substantial  disposition  of
generating assets by formerly  integrated  companies,  the creation of separate,
and in some cases, stand alone,  generating companies and consolidation.  During
2001, however, the pace of transition slowed. This slowdown was due primarily to
public and governmental reactions to issues associated with deregulation efforts
in  California  and  the  collapse  of  the  wholesale   electricity  market  in
California.                                                                     
     At the Federal  level,  the FERC remains  committed to the  development  of
wholesale generation markets. Although its proposal for the development of large
regional  transmission  organizations  (RTOs)  to  facilitate  markets  has been
delayed,  it is planning an initiative to standardize  wholesale  markets in the
United States. At the state level, concerns raised by the California experiences
have stalled new retail  competition  initiatives  and slowed the  separation of
generation from regulated transmission and distribution assets.                 
     Exelon believes that the transition in the electric  utility  industry will
continue,  albeit at a slower pace than  previously,  particularly  at the state
level.   This  slower   transition   will  be  reflected  in  reduced   industry
consolidation  in the near  term and  reduced  disaggregation  of  regulated  to
unregulated services.  These uncertainties may limit opportunities for Exelon to
pursue its plans to expand its generation portfolio.                            
     Exelon also believes that competition for electric  generation services has
created new risks and  uncertainties  in the industry.  Some of these risks were
clearly illustrated in California - the risks of inadequate  generation,  having
load obligations without owning generation,  and price volatility. The situation
in California also illustrated the need for additional infrastructure to support
competitive  markets.  The  uncertainties  include  future  prices of generation
services in both the                                                            

19

EX-99
21st Page of 27
TOC
1st
Previous
Next
Bottom
Just 21st

wholesale  and retail  markets,  supply and demand  volatility,  and  changes in
customer profiles that may impact margins on various electric service offerings.
These  uncertainties  create  additional risk for  participants in the industry,
including  Exelon,  and may result in increased  volatility in operating results
from year to year.                                                              

Energy Delivery                                                                 
Exelon believes that its energy delivery business will provide a significant and
steady  source of earnings  for  investment  in growth  opportunities.  Exelon's
primary goals for its energy delivery companies,  ComEd and PECO, are to deliver
reliable  service,  to  improve  customer  service  and  to  sustain  productive
regulatory  relationships.  Achieving  these goals is  expected to maximize  the
value of Exelon's energy delivery assets.                                       
     Under  restructuring  regulations  adopted at the Federal and state levels,
the role of electric utilities in the supply and delivery of energy is changing.
Energy Delivery  continues to be obligated to provide reliable  delivery systems
under cost-based rates. It remains  obligated,  as a provider of last resort, to
supply generation  service during the transition period to a competitive  supply
marketplace  to customers  who do not or cannot  choose an  alternate  supplier.
Retail competition for generation services has resulted in reduced revenues from
regulated  rates and the sale of  increasing  amounts of energy at  market-based
rates.                                                                          
     Energy  Delivery's  revenues will be affected by rate  reductions  and rate
freezes  currently in effect at ComEd and PECO.  The rate  freezes  limit Energy
Delivery's ability to recover increased expenses and the costs of investments in
new transmission and distribution  facilities through rates. As a result, Energy
Delivery's future results of operations will be dependent on its ability:       

-    to deliver  electricity  and, in the case of PECO,  gas,  to its  customers
     cost-effectively,  particularly  in light of the current  caps on rates and
ComEd capital expenditure requirements,                               
-    to realize cost savings from the Merger and  synergies to offset  increased
     costs on new  investments and inflation while its delivery rates are capped
and,                                                                  
-    to manage its provider of last resort responsibilities.                    

     ComEd's results of operations will be affected by a legislatively  mandated
5% residential base rate reduction that became effective in October 2001, a base
rate freeze that will remain generally  effective until at least January 1, 2005
and the collection of transition  charges through at least 2006.  PECO's results
of operations  will be affected by agreed-upon  rate reductions of $200 million,
in  aggregate,  for the period 2002  through  2005 and caps  (subject to limited
exceptions  for  significant  increases  in  Federal  or  state  taxes  or other
significant  changes in law or regulation  that do not allow PECO to earn a fair
rate of return) on its transmission and distribution  rates through December 31,
2006 as a result of settlements previously reached with the PUC.                
     ComEd's  obligations to make capital  expenditures,  combined with the rate
freeze,  could  affect its  earnings  during the rate  freeze  period.  ComEd is
obligated to make capital  expenditures  with  respect to its  transmission  and
distribution  system,  including  defined  projects  within  the City of Chicago
(City)  as a  result  of a  settlement  agreement  with the City and at least $2
billion  during the period 1999 through 2004 on  transmission  and  distribution
facilities  outside  of the  City as a result  of  Illinois  legislation.  Given
ComEd's   commitments  to  improve  the  reliability  of  its  transmission  and
distribution  system,  ComEd expects that its capital  expenditures  will exceed
depreciation on its rate base assets through at least 2002. The base rate freeze
will  generally  preclude  rate  recovery on and of those  investments  prior to
January 1, 2005.  Unless ComEd can offset the additional  carrying costs against
cost savings,  its return on investment  may be reduced during the period of the
rate freeze and until rate increases are approved authorizing a return of and on
this new investment.                                                            
     PECO's results will be affected by annual  increases in amortization of its
stranded  cost  recovery  through  2010.  PECO has been  authorized  to  recover
stranded  costs of $5.3 billion ($4.9 billion of  unamortized  costs at December
31, 2001) over a twelve-year  period  ending  December 31, 2010 with a return on
the unamortized  balance of 10.75%.  In 2001,  revenue  attributable to stranded
cost  recovery  was $797 million and is scheduled to increase to $932 million by
2010, the final year of stranded cost recovery.  Amortization of PECO's stranded
cost recovery,  which is a regulatory  asset,  is included in  depreciation  and
amortization.  The  amortization  expense  for 2001 was  $271  million  and will
increase to $879 million by 2010.                                               
     A  substantial  portion of Energy  Delivery's  customers  have the right to
choose their electricity  suppliers.  All of ComEd's  non-residential  customers
have this right, and all of its residential customers will have this right as of
May 1, 2002.  All of PECO's retail  customers  have this right.  At December 31,
2001, approximately 21% of ComEd's small commercial and                         

20

EX-99
22nd Page of 27
TOC
1st
Previous
Next
Bottom
Just 22nd

industrial  load,  and 42% of its  large  commercial  and  industrial  load were
purchasing their electric energy from an alternative  electric supplier or chose
the purchase power option,  and approximately 28% of PECO's residential load, 6%
of its small  commercial and industrial load and 5% of its large  commercial and
industrial load were purchasing generation service from an alternate supplier.  
     Provider of last resort  (POLR)  obligations  refer to the  obligation of a
utility  to  provide  generation  services  (i.e.,  power and  energy)  to those
customers who do not take service from an alternative generation supplier or who
choose to come back to the utility  after  taking  service  from an  alternative
supplier.  Because the choice lies with the customer,  these obligations make it
difficult  for the  utility to predict and plan for the level of  customers  and
associated  energy demand. If these  obligations  remain unchanged,  the utility
could be required to maintain  reserves  sufficient to serve 100% of the service
territory  load at a tariffed rate on the chance that  customers who switched to
new suppliers  decide to come back to the utility as a "last resort"  option.  A
significant  over or under estimation of such reserves may cause commodity price
risks for suppliers.  Both ComEd and PECO have entered into long-term agreements
with  Generation to procure their power needs and achieve some certainty  during
the next several  years with  respect to these  obligations.  ComEd's  agreement
allows it to obtain sufficient power at fixed rates.  PECO's agreement allows it
to  obtain  sufficient  power at the  rates it is  allowed  to  charge  to serve
customers who do not choose alternate generation suppliers.                     
     In Illinois, utilities are required to offer bundled rates frozen at levels
established prior to restructuring  legislation until January 2005. The provider
of last resort issue  requires  resolution  in the near term, as the answer will
affect  pricing,  competitive  market  development  and  planning by  utilities,
alternate  suppliers  and  customers.  ComEd  has  made  an  informal  proposal,
regarding its future provider of last resort obligations.  The proposal seeks to
balance the desire for a reliable  supply of electricity  at a reasonable  price
with more price certainty for smaller customers,  such as residential customers,
while  continuing  to develop a  functioning  competitive  wholesale  market for
generation  services.  The proposal  offers large  customers a default power and
energy  offering  at  spot  market  rates,  thereby  freeing  the  utility  from
maintaining  a  long-term  portfolio  and  making  that  capacity  available  to
alternative  suppliers.  The  proposal  affords  certainty  of supply  for large
customers, but not price certainty. Recognizing that small customers may not yet
have the same competitive options as large customers,  the proposal offers small
customers  both supply and price  certainty,  protecting  those  customers  from
market  volatility.  The proposal  would require  regulatory  action in order to
become  effective,  and no  assurance  can be  provided as to the timing of such
action or the ultimate result of such action.                                   
     PECO's rates for generation  services are generally capped through December
2010.  Accordingly,  the  provider of last resort  issue for PECO also  requires
resolution, but in a longer timeframe.                                          

Transmission.  Energy Delivery  provides  wholesale  transmission  service under
rates  established  by FERC.  FERC has used its  regulation of  transmission  to
encourage  competition for wholesale  generation services and the development of
regional  structures to facilitate regional wholesale markets. In December 1999,
FERC issued Order No. 2000 (Order 2000)  requiring  jurisdictional  utilities to
file  a  proposal  to  form  a  regional  transmission  organization  (RTO)  or,
alternatively,   to  describe   efforts  to   participate   in  or  work  toward
participating  in an RTO or explain why they were not  participating  in an RTO.
Order 2000 is generally designed to separate the governance and operation of the
transmission system from generation companies and other market participants.    
     In response  to Order  2000,  ComEd and  several  other  utilities  filed a
business  plan in August  2001 with FERC  describing  the  creation  of Alliance
Transmission  Company,  LLC  (Alliance  Transco or Alliance) as an  independent,
for-profit  transmission  company. In connection with the process leading to the
FERC  filing,  ComEd  issued a  non-binding  declaration  of intent to divest to
Alliance Transco transmission  facilities having a gross book value in excess of
$1 billion. In a related action, ComEd entered into a non-binding  memorandum of
understanding  with National Grid USA (National  Grid),  the proposed manager of
Alliance Transco,  setting forth general principles  relating to the divestiture
and Alliance Transco as a basis for further discussion.                         
     On December 20, 2001, FERC issued several orders relating to RTOs operating
in the Midwest.  In those orders,  FERC,  among other things,  approved  Midwest
Independent  Transmission System Operator,  Inc. (MISO) as an RTO and found that
Alliance  Transco  lacked  sufficient  scope to be a stand-alone  RTO. FERC also
directed   the  Alliance   participants   to  explore  with  the  MISO  how  the

21

EX-99
23rd Page of 27
TOC
1st
Previous
Next
Bottom
Just 23rd

participants'  business  plan can be  accommodated  with  the  MISO  operational
framework  and  dismissed the business plan filed in August 2001 by the Alliance
participants.  In addition,  FERC  determined that National Grid is not a market
participant  within the meaning of Order 2000 and,  thus,  is eligible to become
the managing member of Alliance  Transco if that entity is formed.  FERC further
directed the Alliance participants to file a statement of their plans to join an
RTO,  including  timeframes,  within 60 days.  As a result  of the FERC  orders,
representatives  of ComEd  and the other  Alliance  participants  are  exploring
various RTO participation  options and are meeting with  representatives of MISO
to explore how the  Alliance  Transco may operate  under the MISO.              
     The Alliance  participants,  including ComEd,  filed their discussions with
MISO at the FERC in February 2002,  noting progress as to some issues,  but also
noted negotiations were ongoing. The Alliance  participants also noted that they
were exploring the possibility of filing their business plan within an RTO other
than MISO.                                                                      
     PECO  provides  regional   transmission  service  pursuant  to  a  regional
open-access  transmission  tariff filed by it and the other transmission  owners
who are members of PJM.  PJM is a power pool that  integrates,  through  central
dispatch,  the generation and  transmission  operations of its member  companies
across a 50,000  square  mile  territory.  Under  the PJM  tariff,  transmission
service is provided on a region-wide,  open-access  basis using the transmission
facilities  of the PJM  members  at  rates  based on the  costs of  transmission
service.  PJM's  Office of  Interconnection  is the ISO for PJM (PJM ISO) and is
responsible for operation of the PJM control area and  administration of the PJM
open-access  transmission  tariff. PECO and the other transmission owners in PJM
have turned over control of their  transmission  facilities  to the PJM ISO. The
PJM ISO and the transmission owners who are members of PJM, including PECO, have
filed with FERC for approval of PJM as an RTO. FERC has  conditionally  approved
the PJM RTO.                                                                    

Generation                                                                      
Exelon  believes that its generation and energy  marketing  business will be the
primary  growth  vehicle in the near term.  Exelon's  generation  strategy is to
develop a national  generation  portfolio with fuel and dispatch  diversity,  to
recognize  the cost  savings and  operational  benefits of owning and  operating
substantial  generating  capacity and to optimize the value of Exelon's low-cost
generating capacity through energy marketing expertise.                         
     Generation competes nationally in the wholesale electric generation markets
on the basis of price and service offerings,  utilizing its generation portfolio
to assure customers of energy deliverability.  Generation's  generating capacity
is  primarily  located  in the  Midwest,  Mid-Atlantic  and  Northeast  regions.
Generation  owns a 50%  interest  in  AmerGen  and a 49.9%  interest  in  Sithe.
Generation  has  agreed to supply  ComEd and PECO  with  their  respective  load
requirements  for customers  through 2006 and 2010,  respectively.  Longer term,
ComEd  and  PECO  supply  requirements  will be  significantly  impacted  by the
resolution  of  their  POLR  obligations  and  the  extent  of  retail  customer
switching.  Generation's  future results will be impacted by these uncertainties
and in turn,  their impact on power purchase  agreements with others,  including
Midwest  Generation.  Generation has also  contracted  with Exelon  Energy,  the
competitive retail energy services  subsidiary of Enterprises,  to meet its load
requirements pursuant to its competitive retail generation sales agreements.  In
addition, Generation has contracts to sell energy and capacity to third parties.
To the extent that Generation's resources exceed its contractual commitments, it
markets these resources on a short-term basis or sells them in the spot market. 
     Generation's future results of operations are dependent upon its ability to
operate  its  generating   facilities   efficiently  to  meet  its   contractual
commitments and to sell energy services in the wholesale  markets. A substantial
portion of Generation's capacity, including all of the nuclear capacity, is base
load generation designed to operate for extended periods of time at low marginal
costs.  Nuclear  generation  is  currently  the  most  cost  effective  way  for
Generation  to meet its  commitments  for  sales to  Energy  Delivery  and other
utilities. During 2001, the nuclear generating fleet, including AmerGen operated
at a 94.4%  weighted  average  capacity  factor.  To cost  effectively  meet its
long-term  commitments to provide  energy,  including its commitment to meet the
provider of last  resort load  obligations  of ComEd and PECO,  Generation  must
consistently operate its nuclear generating facilities at high capacity factors.
Generation's planned nuclear capacity factor for 2002 is 91%. Failure to achieve
this capacity level would require Generation to contract or purchase in the spot
market more expensive energy to meet these commitments.  Because of Generation's
reliance on nuclear facilities,  any changes in regulations by the NRC requiring
additional  investments or resulting in increased  operating or  decommissioning
costs of nuclear generating units could adversely affect Generation.            

22

EX-99
24th Page of 27
TOC
1st
Previous
Next
Bottom
Just 24th

     The operating  results of Generation  depend on its level of sales and, for
market  sales,  on the price of  electricity,  which is subject  to  significant
volatility.  Sales and market prices both depend on the demand for  electricity.
Consequently,  operating  results  are  expected to be stronger in the first and
third  quarters  of each year when the  winter and summer  peak  demand  periods
occur.  Additionally,   Generation's  results  of  operations  are  impacted  by
refueling outages of its nuclear units, which reduce the generating availability
of  its  nuclear  units,   as  well  as  increasing   maintenance   and  capital
expenditures. The number of refueling outages, including AmerGen, is expected to
increase  to  eleven  in  2002  from  six  in  2001.   Maintenance  and  capital
expenditures   are  expected  to  increase  by  $80  million  and  $24  million,
respectively  in 2002 as compared to 2001 as a result of the additional  nuclear
refueling outages.                                                              
     Generation  intends to continue to grow its  generation  portfolio  through
asset  acquisitions,  development  of  new  plants,  innovative  application  of
technology,   joint  ventures  and  long-term  contracts.   New  investments  in
generation,  whether purchased or developed, are dependent on the future success
of both the bilateral and spot energy wholesale markets, which are newly created
and  continuing to develop.  Regardless of the approach,  Generation  intends to
remain  disciplined in its  opportunities  to expand its  generation  portfolio,
including its  evaluation of the potential  return on investments as well as the
risks of investments.                                                           
     Generation's  wholesale  marketing  unit,  Power  Team,  uses  Generation's
generation  portfolio,  transmission  rights and expertise to ensure delivery of
generation to wholesale  customers  under  long-term and  short-term  contracts.
Power Team is responsible for supplying the load  requirements of ComEd and PECO
and markets the remaining energy in the wholesale markets.  Power Team also buys
and sells power in the wholesale  markets.  Trading activities were initiated in
2001 and represent a small portion of Power Team's activity.  As of December 31,
2001,  trading  activities  accounted  for less  than 1% of  Generation's  EBIT.
Trading  activities  are  expected  to  increase  modestly  in 2002 and  trading
activity growth will be dependent on the continued  development of the wholesale
energy  markets and Power Team's  ability to manage  trading and credit risks in
those  markets.  The spot  markets  also  involve  the  credit  risks of  market
participants  purchasing  energy,  which Generation may not be able to manage or
hedge. Generation uses financial trading,  primarily to complement the marketing
of its  generation  portfolio.  Generation  intends  to manage the risk of these
activities  through a mix of long-term and  short-term  supply  obligations  and
through  the  use  of  established  policies,  procedures  and  trading  limits.
Financial  trading,  together  with the  effects  of SFAS  No.  133,  may  cause
volatility in Exelon's future results of operations.                            
     Generation has entered into purchase power agreements (PPAs) dated December
18, 2001 and  November  22, 1999 with  AmerGen.  Under the 2001 PPA,  Exelon has
agreed to  purchase  from  AmerGen  all the energy from Unit No. 1 at Three Mile
Island Nuclear Station after December 31, 2001 through  December 31, 2014. Under
the 1999 PPA, Generation has agreed to purchase from AmerGen all of the residual
energy from Clinton through  December 31, 2002.  Currently,  the residual output
approximates  25% of the total output of Clinton.  In 2001,  the amount of power
purchased from AmerGen  recorded in Fuel and Purchased Power in the Consolidated
Statements of Income was $57 million.                                           
     In  addition,  under a service  agreement  dated March 1, 1999,  Generation
provides  AmerGen with  certain  operation  and support  services to the nuclear
facilities owned by AmerGen.  This service  agreement has an indefinite term and
may be terminated by Generation or by AmerGen on 90 days' notice.  Generation is
compensated  for these services in an amount agreed to in the work order but not
less than the higher of fully allocated costs for performing the services or the
market price.  The amount  charged to AmerGen for these services in 2001 was $80
million.                                                                        

Enterprises                                                                     
Enterprises  consists  primarily  of the  infrastructure  services  business  of
InfraSource,  Inc.  (InfraSource),   the  energy  services  business  of  Exelon
Services,  Inc., the competitive  retail energy sales business of Exelon Energy,
Inc.,  the  district  cooling  business of Exelon  Thermal  Technologies,  Inc.,
communications  joint  ventures  and  other  investments  weighted  towards  the
communications,  energy  services and retail services  industries.  InfraSource,
formerly  Exelon  Infrastructure  Services,  Inc. (EIS),  was renamed  effective
November 15, 2001 in order to effectively  unite all of the EIS companies  under
one brand  name.  Enterprises'  results of  operations  will be  affected by its
ability:                                                                        

-    to integrate  various acquired  businesses in the  infrastructure  services
business so as to realize synergies and cost savings, and             
-    to  rationalize  certain  investments  either by  improving  margins or, in
appropriate cases, by disposition to third parties.                   

23

EX-99
25th Page of 27
TOC
1st
Previous
Next
Bottom
Just 25th

     The results of InfraSource's  infrastructure  services  business and Exelon
Services'  energy  services  business  are  dependent  on demand for  outsourced
construction and maintenance  services.  That demand has been driven in the past
by  the  restructuring  of the  electric  utility  industry  and  growth  of the
communications,  cable and internet  industries.  Slowdown in that restructuring
and the current condition of the  communications,  cable and internet industries
means  that  results  will be driven by  efforts  to  manage  costs and  achieve
synergies.                                                                      
     Exelon Energy's  competitive retail energy sales business is dependent upon
continued  deregulation  of retail  electric  and gas markets and its ability to
obtain  supplies of electricity  and gas at competitive  prices in the wholesale
market.  The low margin  nature of the  business  makes it  important to achieve
concentrations of customers with higher volumes so as to manage costs.          
     Enterprises'  investments are weighted toward the communications  industry,
but also include  companies in energy  services and retail  services,  including
e-commerce.  Investments in the  communications  industries  have included joint
ventures with established  companies.  Investments in other areas have generally
been in new entrepreneurial companies with technologies and applications for the
deregulating   energy   marketplace.   Enterprises   continually   monitors  the
performance and potential of its investments and evaluates opportunities to sell
existing  investments and to make new investments.  In the past, Exelon has been
required to write-off or write-down certain investments.  The sale,  write-down,
or  write-off  of  investments  may increase  the  volatility  of earnings.  The
adoption of SFAS No. 142 is expected to result in an impairment of  Enterprises'
goodwill which will be recorded in the first quarter of 2002. See New Accounting
Pronouncements.                                                                 

Other Factors                                                                   
Inflation affects Exelon through increased operating costs and increased capital
costs  for  electric  plant.  As a result  of the rate  caps  imposed  under the
legislation in Illinois and Pennsylvania and price pressures due to competition,
Exelon may not be able to pass the costs of inflation through to customers.     
     In  2001,   Exelon  made   several   changes  to  its  pension   plans  and
postretirement benefit plans including  consolidating the former Unicom and PECO
plans into Exelon plans.  Also, a cash balance pension plan was adopted to cover
essentially  all  management  and  electing  union  employees  hired on or after
January 1, 2001. Management employees who were active participants in the former
Unicom and PECO pension plans on December 31, 2000 and remain employed by Exelon
on January 1, 2002,  will have the opportunity to continue to participate in the
pension  plan or to transfer to the cash  balance  plan.  Exelon also adopted an
amendment to the former Unicom postretirement  medical benefit plan that changed
the eligibility requirement of the plan to cover employees taking their pensions
with ten years of  service  after age 45 rather  than ten years of  service  and
having attained the age of 55.                                                  
     Exelon's  costs of  providing  pension and  postretirement  benefits to its
retirees is dependent upon a number of factors, such as the discount rate, rates
of return on plan assets, and the assumed rate of increase in health care costs.
Although  Exelon's  pension  and  postretirement  expense  is  determined  using
three-year  averaging  and is not as  vulnerable  to a single  year's  change in
rates,  these costs are expected to increase in 2002 and beyond as the result of
the above  noted plan  changes  along with the  affects of the decline in market
value of plan assets,  changes in  appropriate  assumed  rates of return on plan
assets and discount rates,  and increases in health care costs. For a discussion
of Exelon's pension and  postretirement  benefit plans, see Note 16 of the Notes
to Consolidated Financial Statements.                                           

Environmental Exelon's operations have in the past and may in the future require
substantial  capital  expenditures in order to comply with  environmental  laws.
Additionally,  under Federal and state  environmental  laws, Exelon is generally
liable for the costs of remediating environmental  contamination of property now
or formerly owned by Exelon and of property contaminated by hazardous substances
generated  by Exelon.  Exelon  owns or leases a number of real  estate  parcels,
including  parcels on which its  operations or the operations of others may have
resulted in  contamination  by substances  that are considered  hazardous  under
environmental laws. Exelon has identified 72 sites where former manufactured gas
plant (MGP)  activities have or may have resulted in actual site  contamination.
Exelon is currently involved in a number of proceedings  relating to sites where
hazardous  substances  have been  deposited  and may be  subject  to  additional
proceedings in the future.                                                      
     As of December 31, 2001 and 2000,  Exelon had accrued $156 million and $172
million,  respectively,  for environmental  investigation and remediation costs,
including $127 million and $140 million, respectively, for MGP investigation and
remediation that currently can be reasonably estimated. Exelon expects to expend
$35 million for  environmental  remediation                                     

24

EX-99
26th Page of 27
TOC
1st
Previous
Next
Bottom
Just 26th

activities  in  2002.   Exelon  cannot  predict  whether  it  will  incur  other
significant  liabilities for any additional  investigation and remediation costs
at these or additional  sites  identified by Exelon,  environmental  agencies or
others, or whether such costs will be recoverable from third parties.           

Security  Issues and Other Impacts of Terrorist  Actions The events of September
11, 2001 have affected Exelon's operating  procedures and costs and are expected
to affect the cost and  availability  of the  insurance  coverages  that  Exelon
carries.  Exelon has initiated  security measures to safeguard its employees and
critical  operations and is actively  participating  in industry  initiatives to
identify  methods to  maintain  the  reliability  of its energy  production  and
delivery systems.  It is expected that governmental  authorities will be working
to ensure that  emergency  plans are in place and that  critical  infrastructure
vulnerabilities  are  addressed.  The  electric  utility  industry is  proposing
security  guidelines  rather  than  government  mandated  standards  to  protect
critical infrastructures. It is not known if Federal standards will be issued to
the electric or gas industries.  Exelon is evaluating enhanced security measures
at  certain  critical  locations,  enhanced  response  and  recovery  plans  and
assessing  longer term design  changes and redundancy  measures.  These measures
will involve additional expense to develop and implement.                       
     The NRC has placed  all  nuclear  generating  plants on its  highest  alert
status,  requiring  increased  security  measures,  enhanced  communication with
authorities at all levels of government and enhanced  physical  barriers.  These
additional measures are estimated to cost between $600,000 and $900,000 annually
for each of Exelon's ten operating  plants.  Exelon can not predict how long the
NRC will keep nuclear  plants on this  status.  The NRC also has  undertaken  an
initiative to perform a "top to bottom"  review of nuclear  security in light of
the September 11, 2001 events. Exelon cannot predict when the NRC review will be
completed or whether  additional  actions and expenditures will be required as a
result.                                                                         
     Exelon carries nuclear liability  insurance.  The Price-Anderson Act limits
the  liability  of  nuclear  reactor  owners for  claims  arising  from a single
incident.  The current limit is $9.5 billion and is subject to change to account
for the effects of  inflation  and  changes in the number of licensed  reactors.
Through  its  subsidiaries,  Exelon  carries the  maximum  available  commercial
insurance  of $200  million.  The  remaining  $9.3  billion is provided  through
mandatory  participation in a financial  protection pool.  Exelon cannot predict
the effects on  operations of the August 2002  expiration of the  Price-Anderson
Act.                                                                            
     In addition to nuclear  liability  insurance,  Exelon also carries property
damage and liability insurance for its properties and operations. As a result of
significant changes in the insurance  marketplace,  due in part to the September
11, 2001 terrorist acts, the available  coverage and limits may be less than the
amount of  insurance  obtained in the past,  and the  recovery for losses due to
terrorists  acts may be limited.  Exelon is  self-insured to the extent that any
losses may exceed the amount of insurance maintained. Nuclear Electric Insurance
Limited (NEIL),  a mutual  insurance  company to which Exelon belongs,  provides
property and business interruption insurance for Exelon's nuclear operations. In
recent years, NEIL has made distributions to its members.  Exelon's distribution
for 2001 is $69 million,  which was  recorded as a reduction  to  Operating  and
Maintenance expense on Exelon's  Consolidated  Statements of Income. Due in part
to the  September  11, 2001 events,  Exelon  cannot  predict the level of future
distributions, although they are expected to be lower than recent levels.       
     Exelon does not carry any business  interruption  insurance  other than the
NEIL coverage for nuclear  operations.  Damage to Energy  Delivery's  properties
could disrupt the distribution of its and Generation's product and significantly
and adversely affect results of operations. Exelon cannot predict the effects on
operations of the availability of property damage and liability  coverage or any
disruptions to its delivery facilities.                                         
     For a discussion of nuclear insurance and other contingencies,  see Note 20
of the Notes to Consolidated Financial Statements.                              

New Accounting  Pronouncements                                                  
In 2001, the FASB issued SFAS No. 141, "Business  Combinations"  (SFAS No. 141),
SFAS No. 142, SFAS No. 143, and SFAS No. 144  "Accounting  for the Impairment or
Disposal of Long-Lived Assets" (SFAS No. 144).                                  
     SFAS No. 141 requires that all business combinations be accounted for under
the purchase  method of  accounting  and  establishes  criteria for the separate
recognition of intangible assets acquired in business combinations. SFAS No. 141
is effective for business combinations initiated after June 30, 2001.           
     SFAS No.  142  establishes  new  accounting  and  reporting  standards  for
goodwill and  intangible  assets.  Exelon  adopted SFAS No. 142 as of January 1,
2002. Under SFAS No. 142, effective January 1, 2002, goodwill recorded by Exelon
is no longer subject to  amortization.  After January 1, 2002,  goodwill will be
subject to an assessment for impairment  using a two-step fair value            

25

EX-99
Last Page of 27
TOC
1st
Previous
Next
Bottom
Just 27th

based test, the first step of which must be performed at least annually, or more
frequently if events or circumstances  indicate that goodwill might be impaired.
The first step  compares  the fair  value of a  reporting  unit to its  carrying
amount, including goodwill. If the carrying amount of the reporting unit exceeds
its fair value,  the second step is  performed.  The second  step  compares  the
carrying  amount of the goodwill to the fair value of the goodwill.  If the fair
value of goodwill is less than the carrying amount,  an impairment loss would be
reported as a reduction to goodwill and a charge to operating expense, except at
the transition date, when the loss would be reflected as a cumulative  effect of
a change in accounting principle. As of December 31, 2001, Exelon's Consolidated
Balance  Sheets  reflected   approximately  $5.3  billion  in  goodwill  net  of
accumulated amortization,  including $4.9 billion of net goodwill related to the
merger of Unicom and PECO recorded on ComEd's  Consolidated Balance Sheets, with
the remainder related to Enterprises. Annual amortization of goodwill related to
the Merger and to Enterprises of $126 million and $24 million, respectively, was
discontinued  upon adoption of SFAS No. 142. Exelon has completed the first step
of the transitional  impairment analysis which indicated that the ComEd goodwill
is not impaired but that an  impairment  exists with respect to the  Enterprises
goodwill. The second step of the analysis,  which will compare the fair value of
the Enterprises goodwill to the $433 million carrying value at December 31, 2001
has not  yet  been  completed.  The  second  step  analysis  is  expected  to be
completed, and the transitional impairment loss recognized, in the first quarter
of 2002 as a Cumulative Effect of a Change in Accounting Principle.             
     SFAS No. 143 provides  accounting  requirements for retirement  obligations
associated with tangible long-lived assets. Exelon expects to adopt SFAS No. 143
on January 1, 2003.  Retirement  obligations  associated with long-lived  assets
included  within the scope of SFAS No. 143 are those for which  there is a legal
obligation  to settle under  existing or enacted law,  statute,  written or oral
contract or by legal  construction  under the doctrine of  promissory  estoppel.
Adoption of SFAS No. 143 will change the accounting for the  decommissioning  of
Exelon's nuclear generating plants. Currently, Exelon records the obligation for
decommissioning  ratably  over the  lives of the  plants.  The  January  1, 2003
adoption of this standard will require a cumulative effect adjustment  effective
the date of adoption to adjust plant assets and  decommissioning  liabilities to
the  values  they  would  have been had this  standard  been  employed  from the
in-service dates of the plants.                                                 
     The  effect  of  this  cumulative   adjustment  will  be  to  increase  the
decommissioning  liability  to  reflect  a full  decommissioning  obligation  in
current year dollars.  Additionally, the standard will require the accrual of an
asset related to the full amount of the decommissioning  obligation,  which will
be amortized over the remaining lives of the plants.  The difference between the
asset  recognized and the liability  recorded upon adoption of the standard will
be charged to earnings and  recognized as a cumulative  effect,  net of expected
regulatory recovery. The decommissioning  liability to be recorded represents an
obligation  for  the  future  decommissioning  of the  plants,  and as a  result
interest  expense  will be  accrued  on this  liability  until  such time as the
obligation is satisfied.                                                        
     Exelon is in the  process of  evaluating  the impact of SFAS No. 143 on its
financial  statements,  and cannot  determine the ultimate impact of adoption at
this time, however the cumulative effect could be material to Exelon's earnings.
Additionally,  although  over the life of the plant the charges to earnings  for
the depreciation of the asset and the interest on the liability will be equal to
the amounts currently recognized as decommissioning expense, the timing of those
charges will change and in the  near-term  period  subsequent  to adoption,  the
depreciation  of the asset and the interest on the liability  could result in an
increase in expense.                                                            
     SFAS No. 144  establishes  accounting and reporting  standards for both the
impairment  and disposal of long-lived  assets.  This statement is effective for
fiscal years  beginning after December 15, 2001 and provisions of this statement
are generally applied prospectively.  Exelon is in the process of evaluating the
impact of SFAS No.  144 on its  financial  statements,  and does not  expect the
impact to be material.                                                          

Forward-Looking  Statements                                                     
Except for the historical  information contained herein,  certain of the matters
discussed  in this  Report are  forward-looking  statements  that are subject to
risks and  uncertainties.  The factors that could cause actual results to differ
materially  include those discussed herein as well as those listed in Note 20 of
the Notes to Consolidated  Financial  Statements and other factors  discussed in
Exelon's filings with the SEC. Readers are cautioned not to place undue reliance
on these  forward-looking  statements,  which  speak only as of the date of this
Report.  Exelon  undertakes no  obligation  to publicly  release any revision to
these  forward-looking  statements to reflect events or circumstances  after the
date of this Report.                                                            

26

Dates Referenced Herein   and   Documents Incorporated By Reference

				Referenced-On Page
This 8-K Filing		Date		First		Last			Other Filings
		1/1/99		8
		3/1/99		24
		11/22/99		24
		12/31/99		8
		1/1/00		3		7
		10/20/00		2		12			8-K, 8-K/A, U5A
		12/31/00		2		25			U5S/A, 10-K/A, U5S, 10-K, 11-K, U-13-60
		1/1/01		3		25
		6/30/01		26					10-Q
		9/11/01		26
		10/1/01		4					POS AMC
		11/15/01		12		24
		12/15/01		27
		12/18/01		24
		12/20/01		22					POS AMC, 8-K
		12/31/01		2		27			10-K, U5S/A, 11-K, U-13-60/A, U-13-60, 10-K/A, U5S
		1/1/02		14		26
		1/29/02		12					8-K
For The Period Ended		2/28/02
Filed On / Filed As Of		3/7/02
		5/1/02		21					U5S, U-13-60
		6/30/02		12					10-Q, 10-Q/A
		12/18/02		14
		12/31/02		12		24			U5S, 10-K, U-9C-3, 5, 10-K/A, 11-K
		1/1/03		19		27
		1/1/05		21
		12/18/05		14
		12/31/06		21
		12/31/10		21
		12/31/14		24
Top									List All Filings