13

Management's Discussion and Analysis of Financial Condition and Results of
Operations

General

In December 1996,  Pennsylvania  Governor Ridge signed into law the  Electricity
Generation  Customer Choice and Competition Act (Competition Act) which provides
for  the  restructuring  of  the  electric  utility  industry  in  Pennsylvania,
including retail competition for generation beginning in 1999.

     Pursuant to the Competition  Act, in April 1997, the Company filed with the
Pennsylvania Public Utility Commission (PUC) a comprehensive  restructuring plan
detailing its proposal to implement full customer choice of electric  generation
supplier.  The Company's  restructuring plan identified $7.5 billion of stranded
costs (the loss in value of the Company's  electric  generation-related  assets,
which will result from  competition).  In August  1997,  the Company and various
intervenors in the Company's restructuring proceeding filed with the PUC a Joint
Petition for Partial Settlement (Pennsylvania Plan).

     In December  1997,  the PUC rejected the  Pennsylvania  Plan and entered an
Opinion  and Order,  revised in January  1998 (PUC  Restructuring  Order),  that
deregulates the Company's electric generation operations.  The PUC Restructuring
Order  authorizes  the Company to recover  stranded  costs of $4.9  billion on a
discounted  basis,  or $5.3  billion on a  book-value  basis,  over 8-1/2  years
beginning  in 1999.  In  January  1998,  the  Company  filed  appeals of the PUC
Restructuring  Order with the U.S.  District  Court for the Eastern  District of
Pennsylvania (Eastern District Court) and the Commonwealth Court of Pennsylvania
(Commonwealth Court).

     The Company believes that the PUC Restructuring  Order provides  sufficient
details  regarding  the  deregulation  of  the  Company's  electric   generation
operations  to  require  the  Company  to  discontinue  the  use  of  regulatory
accounting  in its  financial  statements  for  those  operations.  The  Company
determined  that at  December  31,  1997,  $5.8  billion of its $7.1  billion of
electric  generation  assets  were  impaired  and it had $2.6  billion  of other
electric generation-related  regulatory assets. Effective December 31, 1997, the
Company  recorded an  extraordinary  charge against income of $3.1 billion ($1.8
billion  net  of  income   taxes)  to  reflect  the  amount  of  such   electric
generation-related  assets which will not be  recovered  from  customers  either
prior to the commencement of competition or under the PUC  Restructuring  Order.
For additional  information  regarding the extraordinary  charge,  see note 4 of
Notes to Consolidated Financial Statements.

     On January 26, 1998, the Company's Board of Directors reduced the quarterly
common stock  dividend from $0.45 per share to $0.25 per share,  effective  with
the dividend  payable on March 31, 1998. The Board of Directors  concluded that,
given the impact of the PUC  Restructuring  Order,  the dividend  reduction  was
necessary to provide the Company with the financial  flexibility  needed to meet
the demands of  competition.  Although the Company  cannot  predict the ultimate
effect of the PUC  Restructuring  Order and competition for electric  generation
services,  the Company believes that its future financial  condition and results
of operations will be adversely affected. See "Outlook-PUC Restructuring Order."


Discussion of Operating Results

Earnings

The Company  recorded a loss per common share of $6.80 in 1997 as compared  with
earnings per share of $2.24 and $2.64 in 1996 and 1995,  respectively.  The loss
in 1997  was  primarily  due to an  extraordinary  charge  of  $8.24  per  share
reflecting the effects of the PUC  Restructuring  Order and  deregulation of the
Company's  electric  generation  operations.  1997 earnings were also reduced by
several  one-time  charges  totaling  $0.56 per share for  changes  in  employee
benefits,  write-offs of  information  systems  development  charges  reflecting
clarification of accounting  guidelines and additional  reserves,  including for
environmental  site  remediation;  by $0.30 per share  for  higher  depreciation
expense  resulting from a full year's increase in depreciation  and amortization
of assets  associated  with Limerick  Generating  Station  (Limerick)  and other
assets;  by $0.12 per share for income tax  adjustments;  by $0.09 per share for
losses  from new  non-utility  ventures;  and by $0.05 per  share for  increased
depreciation  expense due to plant  additions.  These  decreases  were partially
offset by a one-time $0.18 per share  recognition  of income  resulting from the
settlement of  litigation  arising from the current  outage of Salem  Generating
Station (Salem); by $0.08 per share for operational efficiencies;  and by higher
revenues  net of fuel of $0.06 per share  primarily  due to  increased  sales to
other utilities.

     The $0.40 per share  decrease in 1996  earnings was primarily due to higher
Salem  outage-related  replacement  power and  maintenance  costs which  reduced
earnings by $0.27 per share.  Earnings also decreased by $0.18 per share in 1996
due to lower electric revenues resulting from milder weather conditions compared
to 1995;  by $0.12 per share due to the gain  recognized  in 1995 on the sale of
Conowingo  Power  Company  (COPCO);  by $0.11 per  share due to higher  customer
expenses;  and by $0.10 per share due to the  increased  depreciation  of assets
associated  with Limerick.  These  decreases were partially  offset by $0.18 per
share due to the Company's  continuing  cost control  initiatives;  by $0.09 per
share due to savings  resulting  from the  Company's  ongoing debt and preferred
stock  refunding and refinancing  program;  and by $0.08 per share due to higher
revenues resulting from increased sales to other utilities.
<PAGE>
14

Significant Operating Items

<TABLE>
<CAPTION>
Revenue and Expense Items as a Percentage of Total Operating Revenues           Percentage  Dollar Changes
     1995     1996     1997                                                      1997-1996    1996-1995
   <C>      <C>      <C>      <S>                                                  <C>          <C>
      90%      90%      90%    Electric                                               8%           2%
      10%      10%      10%    Gas                                                    5%           4%
     ----     ----     ----                                                         ----       -----
     100%     100%     100%    Total Operating Revenues                               8%           2%
     ====     ====     ====                                                         ====        ====
      18%      23%      28%    Fuel and Energy Interchange                           33%          27%
      30%      30%      31%    Operating and Maintenance                             12%           2%
      11%      11%      12%    Depreciation                                          19%           7%
       8%       7%       7%    Taxes Other Than Income                                4%         (5%)
     ----     ----     ----                                                         ----       -----
      67%      71%      78%    Total Operating Expenses                              19%           9%
     ====     ====     ====                                                         ====        ====
      33%      29%      22%    Operating Income                                    (19%)        (11%)
     ====     ====     ====                                                         ====        ====
    (11%)    (10%)     (9%)    Interest Expense                                     (2%)         (8%)
     ----     ----     ----                                                         ----       -----
     (9%)     (9%)     (8%)    Total Other Income and Deductions                      4%         (9%)
     ----     ----     ----                                                         ----       -----
      24%      20%      14%    Income Before Taxes and Extraordinary Item          (27%)        (18%)
     ----     ----     ----                                                         ----       -----
      10%       8%       6%    Income Taxes                                        (14%)        (21%)
     ----     ----     ----                                                         ----       -----
      14%      12%       8%    Income Before Extraordinary Item                    (35%)        (15%)
     ====     ====     ====                                                         ====        ====
</TABLE>

Operating Revenues

Total  operating  revenues  increased in 1997 by $334 million to $4,618 million.
This represented a $312 million increase in electric  revenues and a $22 million
increase in gas  revenues  over 1996.  The  increase in  electric  revenues  was
primarily  due to  increased  sales  to other  utilities.  The  increase  in gas
revenues was primarily due to higher  revenues from sales to  commercial,  house
heating and residential  customers  resulting from higher  purchased  gas-clause
revenues  charged in 1997  compared  to 1996,  partially  offset by lower  sales
volume  resulting  from milder  weather  conditions  in 1997.  This increase was
partially  offset by  reduced  sales to  interruptible  customers  switching  to
transportation service.

     Total  operating  revenues  increased  in 1996  by $98  million  to  $4,284
million.  This represented an $80 million  increase in electric  revenues and an
$18  million  increase  in gas  revenues  over 1995.  The  increase  in electric
revenues was  primarily  due to increased  sales to other  utilities,  partially
offset by decreased retail sales due to milder weather conditions.  The increase
in gas revenues was primarily due to increased  sales to retail  customers  from
colder  weather  conditions  in the first half of 1996 and higher levels of firm
sales  resulting from customers  switching from  transportation  service to firm
service.   These  increases  were  partially   offset  by  decreased  sales  and
transportation revenues resulting from unusually mild weather in December 1996.

     Increases/(decreases)  in electric sales and operating revenues by class of
customer  for 1997  compared to 1996 and 1996  compared to 1995 are set forth as
follows:

<TABLE>
<CAPTION>
                                         1997 - 1996                      1996 - 1995
                                  Electric          Electric        Electric       Electric
                                   Sales            Revenues         Sales         Revenues
                            (Millions of kWh)  (Millions of $) (Millions of kWh) (Millions of $)
<S>                              <C>           <C>                 <C>           <C>    
Residential                          (48)          $   (1)             (86)          $  (14)
House Heating                       (217)             (12)             121                5
Small Commercial
  and Industrial                     194               30              291               19
Large Commercial
  and Industrial                    (174)             (21)            (555)             (37)
Other                                (61)               8               42                3
Unbilled                             397               45             (862)             (69)
  Service Territory                   91               49           (1,049)             (93)
Interchange Sales                    992               33              439                9
Sales to Other Utilities           8,650              230            6,202              164
  Total                            9,733           $  312            5,592           $   80
</TABLE>


Fuel and Energy Interchange Expense

Fuel and energy interchange  expense increased in 1997 by $318 million to $1,290
million.  The increase was primarily due to purchases needed for increased sales
to other  utilities  and a one-time  billing  credit in 1996 from a  non-utility
generator.  Fuel and energy  interchange  expense as a  percentage  of operating
revenues  increased  from 23% to 28%  principally  due to  purchases  needed for
increased sales to other utilities.

     Fuel and energy  interchange  expense  increased in 1996 by $210 million to
$973 million.  The increase was primarily due to purchases  needed for increased
sales to other utilities,  increased  replacement power costs resulting from the
shutdown of Salem and a net credit to expense in 1995 from certain  energy sales
to other  utilities.  Fuel and energy  interchange  expense as a  percentage  of
operating  revenues  increased  from  18% to 23%  principally  due to  increased
replacement power costs resulting from the shutdown of Salem.
<PAGE>
                                                                              15
Operating and Maintenance Expense

Operating and  maintenance  expense  increased in 1997 by $157 million to $1,431
million  primarily  due to  several  one-time  charges  totaling  $187  million,
including  charges for changes in employee  benefits,  write-offs of information
systems  development charges reflecting  clarification of accounting  guidelines
and additional  reserves,  including for environmental  site remediation.  These
increases were partially  offset by lower  operating  costs at  Company-operated
nuclear  generating  stations  and lower  administrative  and  general  expenses
resulting from the Company's ongoing cost-control efforts.

     Operating  and  maintenance  expense  increased  in 1996 by $23  million to
$1,274 million due to higher  customer  expenses,  higher  contractor  costs and
higher nuclear  generating station charges resulting from the shutdown of Salem.
These   increases   were   partially   offset  by  lower   operating   costs  at
Company-operated  nuclear  generating  stations  and  lower  administrative  and
general expenses resulting from the Company's ongoing cost-control efforts.

Depreciation Expense

Effective October 1, 1996, the Company  increased  depreciation and amortization
on assets  associated  with  Limerick  by $100  million  per year and  decreased
depreciation and amortization on other Company assets by $10 million per year.

     Depreciation  expense increased in 1997 by $92 million to $581 million. The
increase was primarily due to increased  depreciation of assets  associated with
Limerick.  Depreciation  expense  also  increased  due to  additions to plant in
service.

     Depreciation  expense increased in 1996 by $32 million to $489 million. The
increase was primarily due to increased  depreciation of assets  associated with
Limerick.  Depreciation  expense  also  increased  due to  additions to plant in
service.

Interest Charges

Interest charges  decreased in 1997 by $7 million to $402 million.  The decrease
was primarily due to the Company's  ongoing  program to reduce and/or  refinance
higher-cost,   long-term  debt.  This  decrease  was  partially  offset  by  the
replacement  of $62 million of  preferred  stock with Monthly  Income  Preferred
Securities  (MIPS)  in the  third  quarter  of 1997.  MIPS are  recorded  in the
financial  statements  as Company  Obligated  Mandatorily  Redeemable  Preferred
Securities of a Partnership.

     Interest  charges  decreased  in 1996 by $36 million to $409  million.  The
decrease was  primarily due to the  Company's  ongoing  program to reduce and/or
refinance higher-cost, long-term debt. This decrease was partially offset by the
replacement of $78 million of preferred stock with MIPS in the fourth quarter of
1995.

Other Income and Deductions

Other income and deductions  excluding  interest charges increased in 1997 by $6
million to $4 million.  The  increase was  primarily  due to the  settlement  of
litigation arising from the shutdown of Salem. The increase was partially offset
by losses from the Company's  new  non-utility  ventures.  Also  offsetting  the
increase  was  the  write-off  of  one  of  the   Company's   telecommunications
investments  as  a  result  of  the   circumstances   involved  in  the  Federal
Communication  Commission's  auctioning of the personal  communications  systems
"C-block" licenses.

     Other income and deductions excluding interest charges decreased in 1996 by
$60 million to a net deduction of $2 million.  The decrease was primarily due to
the gain recognized in 1995 on the sale of COPCO.

Income Taxes

Income  taxes on operating  and  non-operating  income  decreased in 1997 by $47
million to $293  million.  The decrease  was  primarily  due to lower  operating
income.  The decrease was partially offset by reduced tax depreciation  benefits
from plant and regulatory  assets which are not fully  normalized for ratemaking
purposes.

     Income taxes decreased in 1996 by $92 million to $340 million. The decrease
was primarily due to lower  operating  income and the gain recognized in 1995 on
the sale of COPCO.

Preferred Stock Dividends

Preferred  stock dividends  decreased in 1997 by $1 million to $17 million.  The
decrease was primarily due to the  replacement of $62 million of preferred stock
with MIPS in the third quarter of 1997.

     Preferred stock  dividends  decreased in 1996 by $5 million to $18 million.
The decrease was  primarily due to the  replacement  of $78 million of preferred
stock with MIPS in the fourth quarter of 1995.


Discussion of Liquidity and Capital Resources

The Company's capital resources are primarily  provided by internally  generated
cash flows from  utility  operations  and,  to the  extent  necessary,  external
financing.  Such capital  resources  are  generally  used to fund the  Company's
capital  requirements,  including  investments in new and existing ventures,  to
repay maturing debt and to make preferred and common stock dividend payments.

     In 1997,  1996 and 1995,  internally  generated cash exceeded the Company's
capital requirements and dividend payments. The Company anticipates that it will
be able to meet its capital  requirements  with  internally  generated cash from
utility  operations  in  1998.  Beginning  in 1999,  the  Company  expects  that
internally  generated cash will be reduced due to price pressures resulting from
competition  for  electric  generation  services  and  the  effects  of the  PUC
Restructuring  Order. In  anticipation of this expected  reduction of internally
generated  cash,  in January  1998,  the Board of Directors  voted to reduce the
Company's common stock dividend, effective with the first quarter 1998 dividend.
Based upon the 222.5 million shares of common stock currently  out-


<PAGE>
16

standing,  the common stock  dividend  reduction  will reduce the Company's cash
requirements by $178 million per year.  Absent  increases in the market price of
electric generation services, the Company expects that internally generated cash
will be further reduced in 2007, when the Company  completes the recovery of its
allowed  stranded  costs from  customers.  The  magnitude  of the  reduction  of
internally generated cash will be affected by a number of factors, including how
quickly  electric  generation  competition  develops,  the Company's  ability to
compete, the impact of additional cost-cutting initiatives, future market prices
of  electric  generation  and the  outcome of the  Company's  appeals of the PUC
Restructuring Order.

     The  Competition  Act  authorizes  the  securitization  of the  recovery of
allowed stranded costs. Under the Competition Act,  securitization proceeds must
be  used   principally   to  reduce   qualified   stranded   costs  and  related
capitalization.  Unless extended by the PUC, the Company has authorization until
May 22, 1998 to securitize  $1.1 billion of stranded  costs. It is unlikely that
the Company will  securitize the recovery of its stranded costs until appeals of
the PUC  Restructuring  Order are resolved.  If the Company does securitize,  it
cannot predict the level of stranded cost recovery that it would be permitted to
securitize or the impact of such securitization on the Company's capitalization.

     At December 31, 1997, the Company's  capital  structure  consisted of 36.8%
common equity; 7.9% preferred stock and Company obligated mandatorily redeemable
preferred securities (which comprised 4.8% of the Company's total capitalization
structure); and 55.3% long-term debt.

     The  Company  expects its level of net  capital  investment  to decrease in
future years. Total capital expenditures, primarily for utility plant, were $573
million  in 1997  and are  estimated  to be $600  million  in  1998.  Due to the
expected  adverse  impact of the PUC  Restructuring  Order and  competition  for
electric  generating  services on its future capital  resources,  the Company is
currently  evaluating  its  capital  commitments  for 1999 and  beyond.  Certain
facilities  under  construction  and to be constructed  may require  permits and
licenses which the Company has no assurance will be granted.

     The  Company's  operations  have in the past and may in the future  require
substantial capital expenditures in order to comply with environmental laws.

     The Company has  undertaken a number of new ventures,  principally  through
its   Telecommunications   Group,   some  of  which  require   significant  cash
commitments.  For 1998,  the Company's  expected  capital  expenditures  include
approximately $150 million in such ventures.

     Cash flows from  operations  were  $1,038  million in 1997 as  compared  to
$1,172  million  in 1996 and  $1,240  million  in 1995.  Cash  flows  consist of
earnings, non-cash charges of depreciation and deferred income taxes

     Cash  flows  used in  investing  activities  were $573  million  in 1997 as
compared to $663  million in 1996 and $465 million in 1995.  Expenditures  under
the Company's  construction program decreased in 1997. The Company has also made
significant  investments in diversified  activities and other  obligations.  Net
funds  used in these  activities  in 1997 were $83  million,  consisting  of $26
million  for   telecommunications   ventures,  $54  million  for  nuclear  plant
decommissioning  trust funds and $3 million for other deposits and ventures.  In
1996 and 1995,  funds  used in  similar  activities  were $114  million  and $82
million, respectively. 1995 cash flows benefited from the sale of COPCO.

     Cash  flows  used in  financing  activities  were $461  million  in 1997 as
compared to $501 million in 1996 and $802 million in 1995. The decreases in 1997
and 1996 were primarily due to less available cash permitting fewer  retirements
of higher-cost debt.

     The Company meets its short-term liquidity  requirements  primarily through
the  issuance of  commercial  paper and  borrowings  under an  unsecured  credit
facility with a group of banks. The Company had $402 million of short-term debt,
including $314 million of commercial paper, outstanding at December 31, 1997.

     At December 31, 1997,  the  Company's  embedded  cost of debt was 6.9% with
12.0% of the Company's  long-term debt having floating rates. As a result of the
extraordinary  charge in December  1997, the Company does not expect to meet the
earnings  test  under  the  Company's  mortgage  required  for the  issuance  of
additional bonds against property additions for the twelve months ended December
31,  1998.  As  of  December  31,  1997,  the  Company  was  entitled  to  issue
approximately $3.6 billion of mortgage bonds without regard to the earnings test
against  previously  retired  mortgage bonds.  As a result of the  extraordinary
charge,  the  Company  also does not  expect  to meet the  coverage  test  under
Company's  Articles of  Incorporation  required for the  issuance of  additional
preferred stock for the twelve months ended December 31, 1998.

     The  Company  cannot  predict  whether  the  Competition  Act  or  the  PUC
Restructuring Order will ultimately affect the Company's credit ratings.

Outlook

The Company is entering a period of financial  uncertainty with the deregulation
of its electric  generation  operations in which revenues from  regulated  rates
will be replaced by revenues from the competitive sale of electric generation at
market  prices.  The Company  believes  that the  deregulation  of its  electric
generation  operations and other  regulatory  initiatives  designed to encourage
competition  will increase the Company's risk profile by changing and increasing
the number of factors upon which the Company's  financial results are dependent.
This  may  result  in  more  volatility  in  the  Company's  future  results  of
operations.  The Company  believes that it has significant  advantages that will
assist it in the increasingly competitive electric generation environment. These
advantages include the ability to produce  electricity at a low marginal cost, a
high reserve  margin and the  demonstrated  ability to  efficiently  operate its
electric generation facilities.

     The Company's future financial  condition and its results of operations are
substantially  dependent  upon the  effects of the  Competition  Act and the PUC
Restructuring  Order.  Additional  factors that affect the  Company's  financial
condition  and results of  operations  include  operation of nuclear  generating
facilities, sales to other utilities,  accounting issues, inflation, weather and
compliance with environmental regulations.

     Another factor affecting the Company's  future  financial  condition is its
ability to develop its investments in new ventures into profitable enterprises.
<PAGE>
                                                                              17

PUC Restructuring Order

The   Competition   Act  was  enacted  in  December  1996,   providing  for  the
restructuring of the electric utility industry in Pennsylvania, including retail
competition  for generation  beginning in 1999. The Competition Act requires the
unbundling  of electric  services  into separate  generation,  transmission  and
distribution  services with open retail  competition  for  generation.  Electric
distribution  and  transmission  services will remain  regulated by the PUC. The
Competition  Act requires  utilities to submit to the PUC  restructuring  plans,
including  their  quantification  of  stranded  costs  which  will  result  from
competition.  The  Competition  Act  authorizes  the recovery of stranded  costs
through  charges  to  distribution  customers  for up to nine  years  (or for an
alternative  period  determined  by the PUC for good cause  shown).  During that
period,  the utility is subject to a rate cap which  provides that total charges
to customers  cannot  exceed rates in place as of December 31, 1996,  subject to
certain exceptions.  The Competition Act also caps transmission and distribution
rates  from  December  31,  1996  through  June 30,  2001,  subject  to  certain
exceptions.

     Pursuant to the Competition  Act, in April 1997, the Company filed with the
PUC a  comprehensive  restructuring  plan. In December 1997, the PUC adopted its
own  restructuring  plan which  deregulates  the Company's  electric  generation
operations and allows the Company to recover stranded costs of $4.9 billion on a
discounted  basis,  or $5.3  billion on a book  value  basis,  over 8-1/2  years
beginning in 1999. Recovery of allowed stranded costs will be through a separate
charge to be levelized  over the recovery  period using a 7.47% cost of capital.
Other major provisions of the PUC  Restructuring  Order include capping customer
bills at the year-end 1996 system-wide  average of 9.95 cents per kWh; beginning
January  1,  1999,   unbundling  rates  into  a  transmission  and  distribution
component, the charge for recovery of stranded costs and a "shopping credit" for
generation;  and phasing in customer choice of electric  generation supplier for
all customers in three steps,  one-third of the peak load of each customer class
on  January  1,  1999,  one-third  on  January  2, 1999 (one day  later) and the
remainder on January 2, 2000. To encourage competition,  the PUC established the
"shopping credit" for generation in excess of current market prices.

     On January 21, 1998, the Company filed a complaint in the Eastern  District
Court seeking injunctive and monetary relief on the grounds that the Competition
Act and the PUC Restructuring  Order: (1) are preempted by Section 201(b) of the
Federal  Power  Act;  (2)  effect a taking  of  private  property  without  just
compensation  in violation of the Fifth and  Fourteenth  Amendments  to the U.S.
Constitution;  (3) violate the Due Process  Clause,  the Contract Clause and the
First Amendment of the U.S. Constitution; and (4) deprive the Company of certain
other federally protected rights .

     On January 22,  1998,  the Company  filed two  Petitions  for Review in the
Commonwealth  Court appealing the PUC  Restructuring  Order. The petitions state
that the PUC  Restructuring  Order  must be set aside  because  it is based upon
errors  of  law,  is not  supported  by  substantial  evidence,  constitutes  an
arbitrary and  capricious  abuse of  administrative  discretion and deprives the
Company of the due process of law, to which it is  entitled  under  Article I of
the Pennsylvania Constitution.

Uncertainties of Electric Generation Restructuring

Competition  in wholesale and retail  electric  generation is expected to create
new uncertainties in the utility industry.  These  uncertainties  include future
prices of  electricity  in both the  retail  and  wholesale  markets,  potential
changes in the Company's sales portfolio and supply and demand volatility.

     The Company expects that deregulation of the Company's electric  generating
operations will result in price pressures that will reduce the Company's  future
revenues.  While the  Company  cannot  predict  the  ultimate  impact of the PUC
Restructuring  Order on customer  bills,  the PUC estimates  that customers will
save up to 15% of their total  electric bill  beginning in 1999 through June 30,
2007 and will save 30% of their total electric bill thereafter.

     Competition  is also  expected to affect the  ultimate  composition  of the
Company's  electricity  sales.  The  "shopping  credit"  established  by the PUC
encourages  electric retail  customers to choose a supplier.  The Company cannot
predict how successful its affiliated  generation marketers will be in competing
for these customers and customers elsewhere in Pennsylvania.  To the extent that
the Company  loses retail  customers,  it will be  compelled to sell  generation
previously used to serve retail customers in the wholesale market. Since margins
in the wholesale  market are  currently  lower than in the retail  market,  this
could adversely affect the Company's profit margins.

     The Company is a low marginal-cost electricity producer, which puts it in a
favorable position to take advantage of opportunities in the electric retail and
wholesale generation markets. The Company's  competitive position and its future
financial  condition  and results of  operations  are dependent on the Company's
ability to successfully operate its low marginal-cost power plants.

     The Company enters into commitments to buy and sell power. Currently, these
commitments make the Company a net power  purchaser.  Since the price and supply
volatility  of  electricity  generation  cannot be predicted  at this time,  the
Company's  position as a net purchaser  exposes it to risk to the extent that it
has  entered  into  contracts  that may  require  the  Company to pay prices for
purchased power in excess of market prices.

     The Company, as the local distribution provider, is obligated under the PUC
Restructuring  Order to serve as the electric generation supplier of last resort
in its service territory.  This obligation will include all customers who do not
elect to choose an electricity  supplier as well as all customers who seek a new
energy  supplier  but are  unable  to reach a  service  agreement  with  another
supplier.  The Company's rates are capped at 1996 levels.  If energy prices rise
above that level,  the Company would still be obligated to serve these customers
at the capped rate.

Other Competitive Initiatives

During 1996, the Federal Energy  Regulatory  Commission  (FERC) issued Order No.
888 which requires public utilities to file open-access transmission tariffs for
wholesale transmission services in accordance with non-discriminatory  terms and
conditions  established  by the FERC.  

     In response to Order No. 888, in December  1996,  the Company and the other
members of PJM  Interconnection,  L.L.C.  (PJM) filed a joint compliance  filing
with the FERC 
<PAGE>
18

proposing to  restructure  PJM. In November 1997, the FERC issued an order which
allows for the establishment of an Independent  System Operator (ISO) to operate
the  day-to-day  operations  of PJM.  Transmission  service  is on a  pool-wide,
open-access basis using the transmission  facilities of the eight historical PJM
companies with a flat rate based on the costs of the  transmission  system where
the point of delivery is located  (thus  there are eight  rates).  By January 1,
2003, PJM is required to have in place a uniform system-wide transmission rate.

     The  Company  received  approval  from  the  FERC to  remove  the  existing
cost-based  cap  on  prices  charged  for  power  purchased  by the  Company  in
anticipation  of later  resale  in the  wholesale  market  and  certain  changes
regarding the terms of the buy-for-resale  agreements. The new tariff provisions
allow the Company to  purchase  and re-sell  energy at  market-based  rates both
within PJM and outside PJM.

     The gas industry is continuing to undergo structural changes in response to
FERC  policies  designed to increase  competition.  FERC  policies have required
interstate  gas  pipelines  to  unbundle  their gas  sales  service  from  other
regulated tariff services,  such as transportation and storage.  In anticipation
of these changes,  the Company has modified its gas purchasing  arrangements  to
enable the  purchase  of gas and  transportation  at lower  cost.  The  Company,
through  Horizon Energy Company,  a wholly owned  subsidiary,  has  successfully
participated  in pilot programs  outside the Company's gas service  territory to
market natural gas and other services.

     There is an initiative in the  Pennsylvania  legislature  to deregulate the
gas  industry,  which has the support of  Governor  Ridge.  The  Company  cannot
predict  whether  the  Pennsylvania  legislature  will  enact  legislation  that
deregulates the gas industry or whether Governor Ridge will ultimately sign into
law any such legislation.  The Company cannot predict the ultimate effect of gas
industry   deregulation  on  its  future  financial   condition  or  results  of
operations.

     As a  result  of  competitive  pressures,  the  Company  has  continued  to
negotiate  long-term  contracts  with  many  of  its  larger-volume   industrial
customers. Although these agreements have generally resulted in reduced margins,
they have permitted the Company to retain these customers.

Regulation and Operation of Nuclear Generating Facilities

The  Company's  financial  condition  and  results  of  operations  are in  part
dependent  on the  continued  successful  operation  of its  nuclear  generating
facilities.  The Company's nuclear generating facilities represent approximately
44% of its installed generating  capacity.  Because of the Company's reliance on
its  nuclear  generating  units,  any  changes  in  regulations  by the  Nuclear
Regulatory  Commission  (NRC) requiring  additional  investments or resulting in
increased operating costs of nuclear generating units could adversely affect the
Company.

     During  1997,   Company-operated   nuclear   plants   operated  at  an  90%
weighted-average  capacity factor and Company-owned nuclear plants operated at a
73% weighted-average capacity factor.  Company-owned nuclear plants produced 39%
of the Company's  electricity,  despite the shutdown of the Salem units. Nuclear
generation is the most cost-effective way for the Company to meet customer needs
and commitments for sales to other utilities.

     Public  Service  Electric  and Gas Company  (PSE&G),  the operator of Salem
Units No. 1 and No. 2, which are 42.59% owned by the Company,  removed the units
from service in the second quarter of 1995.  PSE&G informed the NRC at that time
that it had  determined  to keep the Salem  units shut down  pending  review and
resolution of certain  equipment and  management  issues and NRC agreement  that
each unit is sufficiently prepared to restart. Unit No. 2 returned to service on
August 30,  1997 and Unit No. 1 is  expected  to return to  service  late in the
first  quarter of 1998.  The  Company  expects to incur and expense at least $20
million in 1998 for increased costs related to the shutdown.  As of December 31,
1997,  1996 and 1995, the Company had incurred and expensed  $152,  $149 and $50
million,  respectively,  for replacement  power and maintenance costs related to
the shutdown of Salem. See note 5 of Notes to Consolidated Financial Statements.

Sales to Other Utilities

The Company's  electric utility  operations  include the wholesale  marketing of
electricity.  At  December  31,  1997,  the Company  had  long-term  commitments
relating  to  the  purchase  from  unaffiliated  utilities  and  others,  energy
associated  with 1,330  megawatts  (MW) of  capacity  in 1998,  with 2,540 MW of
capacity  during  the period  1999  through  2002 and with 2,430 MW of  capacity
thereafter.  These purchases will be utilized  through a combination of sales to
jurisdictional  customers,  long-term  sales to other  utilities and open-market
sales. Under some of these contracts,  the Company may purchase,  at its option,
additional  power as needed.  The Company's  future  results of  operations  are
dependent  in  part on its  ability  to  successfully  market  the  rest of this
generation. See note 5 of Notes to Consolidated Financial Statements.

     In the  wholesale  market,  the  Company has  increased  its sales to other
utilities, but increased competition has reduced the Company's profit margins on
these  sales.  At December  31,  1997,  the Company had entered  into  long-term
agreements with  unaffiliated  utilities to sell energy associated with 4,280 MW
of capacity,  of which 540 MW of these agreements are for 1998, 1,700 MW are for
1999 through 2002 and the remaining 2,040 MW extend through 2022.

Accounting Issues

Effective  December  31,  1997,  the  Company  discontinued  accounting  for its
electric  generation  operations  in  accordance  with  Statement  of  Financial
Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types
of  Regulation."  For further  information,  see note 4 of Notes to Consolidated
Financial  Statements.  The Company believes that its electric  transmission and
distribution  system and gas operations  continue to meet the provisions of SFAS
No.  71.  The  Company  believes  that it is  probable  that  regulatory  assets
associated with these operations will be recovered.

     In 1997, the Financial  Accounting  Standards  Board (FASB) issued SFAS No.
130, "Reporting  Comprehensive Income," to establish standards for reporting and
display of comprehensive income and its components in financial statements.  The
new standard requires an entity to classify items of other comprehensive  income
by their nature in a financial  statement and to display the accumulated balance
of other  comprehensive  income separately from retained earnings and 


<PAGE>
                                                                              19

additional  paid in capital in the equity  section of a statement  of  financial
position.  The new  standard  is  effective  for fiscal  years  beginning  after
December 15, 1997. The Company will adopt SFAS No. 130 in 1998. Adoption of SFAS
No.  130 will not  affect  the  Company's  financial  condition  or  results  of
operations.  The Company is evaluating the impact on its  disclosures,  but does
not expect SFAS No. 130 to materially change its disclosures.

     In 1997,  the FASB issued SFAS No. 131,  "Disclosures  About Segments of an
Enterprise  and Related  Information,"  to  establish  standards  for  reporting
information  about  operating  segments in annual  financial  statements  and to
require reporting of selected  information  about operating  segments in interim
financial  reports issued to  shareholders.  It also  establishes  standards for
related  disclosures about products and services,  geographical  areas and major
customers.  The new  standard is  effective  for fiscal  years  beginning  after
December  31,  1997.  Adoption  of SFAS No. 131 will not  affect  the  Company's
financial  condition or results of  operations.  The Company is  evaluating  the
impact on its operating segment disclosures.

     During 1996,  the FASB issued the Exposure  Draft  "Accounting  for Certain
Liabilities  Related to Closure or Removal of  Long-Lived  Assets." The FASB has
expanded the scope of the project to include closure or removal liabilities that
are incurred at any time in the operating life of the related  long-lived asset.
The FASB has decided that it should proceed toward either a final Statement or a
revised  Exposure  Draft.  The timing of this project is still to be determined.
Until such time that the final  Statement is issued,  the Company will be unable
to  determine  what,  if any,  effect  this issue  might  have on its  financial
condition  or  results  of  operations.  See  note 5 of  Notes  to  Consolidated
Financial Statements.

Other Factors

Annual and quarterly operating results can be significantly affected by weather.
Since the Company's peak demand is in the summer months,  temperature variations
in summer months are generally more  significant  than variations  during winter
months.

     Inflation  affects  the  Company  through  increased  operating  costs  and
increased  capital costs for utility plant. As a result of the rate caps imposed
by the  Competition  Act,  the  elimination  of the Energy Cost  Adjustment  and
expected  price  pressures  due to  competition,  the Company  may have  limited
opportunity to pass the costs of inflation through to customers.

     The Year 2000 issue is the result of computer  programs being written using
two digits rather than four to define the applicable year and other  programming
techniques  which  constrain date  calculations  or assign  special  meanings to
certain dates. Any of the Company's  computer  systems that have  date-sensitive
software  or  microprocessors  may  recognize a date using "00" as the year 1900
rather  than  the  year  2000.   This  could  result  in  a  system  failure  or
miscalculations  causing  disruptions  of  operations,  including,  among  other
things,  a temporary  inability to process  transactions,  send bills or operate
electric generation stations.

     The  Company has  determined  that it will be required to modify or replace
significant  portions of its software so that its computer systems will properly
utilize dates beyond December 31, 1999. The Company presently believes that with
modifications  to existing  software and  conversions to new software,  the Year
2000 Issue can be mitigated.  However, if such modifications and conversions are
not made, or are not completed timely, the Year 2000 Issue could have a material
adverse  impact on the operations  and financial  condition of the Company.  The
costs  associated  with this potential  impact are speculative and not presently
quantifiable.

     The Company  initiated  formal  communications  with all of its significant
suppliers  in March  1997 to  determine  the  extent  to which  the  Company  is
vulnerable to the suppliers' failure to remediate their own Year 2000 issue. The
Company's  estimated  total Year 2000 project costs include the estimated  costs
and time associated with the impact of Year 2000 issues of third parties and are
based on presently  available  information.  There can be no guarantee  that the
systems of other  companies on which the  Company's  systems rely will timely be
converted, or that a failure to convert by another company, or a conversion that
is  incompatible  with the Company's  systems,  would not have material  adverse
impact on the Company.

     The Company will utilize both internal and external resources to reprogram,
or replace,  and test software and computer systems for Year 2000 modifications.
Management  believes that adequate  resources are being devoted to the Year 2000
Issue.  The Company  plans to complete the Year 2000 project not later than June
1, 1999.  To date,  the Company has funded the Year 2000  project  from  current
operating cash flows as a base level of activity for the preliminary  efforts in
connection  with its Year 2000  assessment  and  remediation  plan.  The Company
expects the  remaining  costs of the Year 2000 project to be  approximately  $25
million.

     The  costs  of the  project  and the  date on which  the  Company  plans to
complete the Year 2000  modifications  are based on Management's best estimates,
which were derived utilizing numerous assumptions of future events including the
continued availability of certain resources,  third-party modification plans and
other factors.  However,  there can be no guarantee that these estimates will be
achieved;  actual  results could differ  materially  from those plans.  Specific
factors that might cause such material  differences include, but are not limited
to, the availability and cost of personnel  trained in this area, the ability to
locate and correct all  relevant  computer  programs  and  microprocessors,  and
similar uncertainties.

     The  Company'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,  the  Company  is
generally  liable for the costs of remediating  environmental  contamination  of
property now or formerly  owned by the Company and of property  contaminated  by
hazardous  substances  generated  by the  Company.  The Company 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 which are
considered hazardous under environmental laws. The Company is currently involved
in a number of proceedings  relating to sites where  hazardous  


<PAGE>
20

substances  have been deposited and may be subject to additional  proceedings in
the future.

     The Company has  identified  27 sites where former  manufactured  gas plant
(MGP) activities have or may have resulted in site contamination. The Company is
presently  engaged in  performing  various  levels of activities at these sites,
including  initial  evaluation  to  determine  the  existence  and nature of the
contamination,  detailed evaluation to determine the extent of the contamination
and the necessity and possible  methods of remediation,  and  implementation  of
remediation.   The  Pennsylvania  Department  of  Environmental  Protection  has
approved  the  Company's  clean-up of two sites.  Six other sites are  currently
under some degree of active study and/or remediation.

     As of  December  31,  1997 and 1996,  the  Company  had accrued $63 and $28
million,  respectively,  for environmental  investigation and remediation costs,
including  $35  and  $16  million,   respectively,  for  MGP  investigation  and
remediation that currently can be reasonably  estimated.  The Company expects to
expend $5 million for environmental  remediation activities in 1998. The Company
cannot currently predict whether it will incur other significant liabilities for
any additional  investigation and remediation costs at these or additional sites
identified  by the Company,  environmental  agencies or others,  or whether such
costs will be recoverable from third parties.

     For a discussion of other  contingencies,  see notes 3, 4 and 5 of Notes to
Consolidated Financial Statements.

Forward-Looking Statements

Except for the historical  information contained herein,  certain of the matters
discussed  in this Report are  forward-looking  statements  which are subject to
risks and  uncertainties.  The factors that could cause actual results to differ
materially  include those discussed herein as well as those listed in notes 3, 4
and 5 of Notes to Consolidated  Financial Statements and other factors discussed
in the Company's  filings with the Securities and Exchange  Commission.  Readers
are cautioned not to place undue reliance on these  forward-looking  statements,
which  speak  only as of the date of this  Report.  The  Company  undertakes  no
obligation to publicly release any revision to these forward-looking  statements
to reflect events or circumstances after the date of this Report.



<PAGE>
                                                                              21

Report of Independent Accountants


To the Shareholders and Board of Directors
PECO Energy Company:


     We have audited the accompanying consolidated balance sheets of PECO Energy
Company  and  Subsidiary  Companies  as of December  31, 1997 and 1996,  and the
related  consolidated  statements of income,  cash flows,  and changes in common
shareholders'  equity  and  preferred  stock for each of the three  years in the
period  ended   December  31,  1997.   These   financial   statements   are  the
responsibility of the Companies' management. Our responsibility is to express an
opinion on these financial statements based on our audits.

     We conducted  our audits in accordance  with  generally  accepted  auditing
standards.  Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement.  An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements.  An audit also includes
assessing the  accounting  principles  used and  significant  estimates  made by
management,  as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.

     In our opinion,  the financial statements referred to above present fairly,
in all material  respects,  the consolidated  financial  position of PECO Energy
Company  and  Subsidiary  Companies  as of December  31, 1997 and 1996,  and the
consolidated  results of their  operations  and their cash flows for each of the
three years in the period ended December 31, 1997, in conformity  with generally
accepted accounting principles.






Coopers & Lybrand LLP

2400 Eleven Penn Center
Philadelphia, Pennsylvania
February 2, 1998


<PAGE>
Consolidated Statements of Income
<TABLE>
<CAPTION>
For the Years Ended December 31,                                  1997                1996                1995
                                                                                          Thousands of Dollars
<S>                                                        <C>                 <C>                 <C>        
Operating Revenues
Electric                                                   $ 4,166,669         $ 3,854,836         $ 3,775,326
Gas                                                            451,232             428,814             410,830
                                                           -----------         -----------         -----------
     Total Operating Revenues                                4,617,901           4,283,650           4,186,156
                                                           -----------         -----------         -----------
Operating Expenses
Fuel and Energy Interchange                                  1,290,164             972,380             762,762
Operating and Maintenance                                    1,431,420           1,274,222           1,251,273
Depreciation                                                   580,595             489,001             457,254
Taxes Other Than Income                                        310,091             299,546             314,071
                                                           -----------         -----------         -----------
     Total Operating Expenses                                3,612,270           3,035,149           2,785,360
                                                           -----------         -----------         -----------
Operating Income                                             1,005,631           1,248,501           1,400,796
                                                           -----------         -----------         -----------
Other Income and Deductions
Interest Expense                                              (372,857)           (382,443)           (423,711)
Company Obligated Mandatorily Redeemable
     Preferred Securities of a Partnership, which
     holds Solely Subordinated Debentures of
     the Company                                               (28,990)            (26,723)            (20,987)
Allowance for Funds Used During Construction                    21,771              19,947              27,050
Settlement of Salem Litigation                                  69,800                  --                  --
Gain on Sale of Subsidiary                                          --                  --              58,745
Other, net                                                     (66,028)             (1,976)               (444)
                                                           -----------         -----------         -----------
     Total Other Income and Deductions                        (376,304)           (391,195)           (359,347)
                                                           -----------         -----------         -----------
Income Before Income Taxes and Extraordinary Item              629,327             857,306           1,041,449

Income Taxes                                                   292,769             340,101             431,717
                                                           -----------         -----------         -----------
Income Before Extraordinary Item                               336,558             517,205             609,732

Extraordinary Item (net of $1,290,961 income taxes)         (1,833,664)                 --                  --
                                                           -----------         -----------         -----------
Net (Loss) Income                                           (1,497,106)            517,205             609,732
Preferred Stock Dividends                                       16,804              18,036              23,217
                                                           -----------         -----------         -----------
Earnings Applicable to Common Stock                        $(1,513,910)        $   499,169         $   586,515
                                                           ===========         ===========         ===========
Average Shares of Common Stock
     Outstanding (Thousands)                                   222,543             222,490             221,859
                                                           ===========         ===========         ===========
Basic and Dilutive Earnings per Average Common
     Share Before Extraordinary Item (Dollars)             $      1.44         $      2.24         $      2.64
Extraordinary Item (Dollars)                               $     (8.24)                 --                  --
                                                           -----------         -----------         -----------
Basic and Dilutive Earnings per Average
     Common Share (Dollars)                                $     (6.80)        $      2.24         $      2.64
                                                           ===========         ===========         ===========
Dividends per Common Share (Dollars)                       $      1.80         $     1.755         $      1.65
                                                           ===========         ===========         ===========
</TABLE>

See Notes to Consolidated Financial Statements.


<PAGE>
                                                                              23
Consolidated Statements of Cash Flows

<TABLE>
<CAPTION>
For the Years Ended December 31,                                   1997               1996                 1995
                                                                                           Thousands of Dollars
<S>                                                         <C>                 <C>                 <C>        
Cash Flows from Operating Activities
Net Income                                                  $(1,497,106)        $   517,205         $   609,732
Extraordinary Item (net of $1,290,961 income taxes)          (1,833,664)                 --                  --
                                                            -----------         -----------         -----------
Income Before Extraordinary Item                                336,558             517,205             609,732
Adjustments to reconcile Net Income to Net Cash
          provided by Operating Activities:
     Depreciation and Amortization                              664,294             566,412             531,299
     Deferred Income Taxes                                      (17,228)            166,771             183,514
     Salem Litigation Settlement                                 69,800                  --                  --
     Gain on Sale of Subsidiary                                      --                  --             (58,745)
     Deferred Energy Costs                                       (5,652)            (66,151)            (71,104)
     Amortization of Leased Property                             39,100              31,400              42,900
     Changes in Working Capital:
          Accounts Receivable                                  (289,610)             53,681              (8,198)
          Inventories                                            28,628              (2,729)            (10,872)
          Accounts Payable                                       93,881             (86,765)             (4,686)
          Other Current Assets and Liabilities                   58,539             (25,040)              9,641
     Deferred Credits - Other                                    78,846              (4,609)              5,172
     Other Items affecting Operations                           (19,005)             22,070              11,683
                                                            -----------         -----------         -----------
Net Cash Flows from Operating Activities                      1,038,151           1,172,245           1,240,336
                                                            -----------         -----------         -----------

Cash Flows from Investing Activities
Investment in Plant                                            (490,200)           (548,854)           (532,614)
Proceeds from Sale of Subsidiary                                     --                  --             150,000
Increase in Other Investments                                   (83,261)           (114,126)            (82,041)
                                                            -----------         -----------         -----------
Net Cash Flows from Investing Activities                       (573,461)           (662,980)           (464,655)
                                                            -----------         -----------         -----------

Cash Flows from Financing Activities
Change in Short-Term Debt                                       114,000             287,500             (11,499)
Issuance of Common Stock                                            117              11,301              15,585
Retirement of Preferred Stock                                   (61,895)                 --             (78,105)
Issuance of Company Obligated Mandatorily Redeemable
     Preferred Securities of a Partnership                       50,000                  --              81,032
Issuance of Long-Term Debt                                      161,813              43,700             182,540
Retirement of Long-Term Debt                                   (283,303)           (427,463)           (575,713)
Loss on Reacquired Debt                                          22,752              24,724              12,302
Dividends on Preferred and Common Stock                        (417,383)           (411,569)           (390,340)
Change in Dividends Payable                                      (5,438)              1,685               5,626
Expenses of Issuing Long-Term Debt and Capital Stock             (2,084)                890                (577)
Capital Lease Payments                                          (39,100)            (31,400)            (42,900)
                                                            -----------         -----------         -----------
Net Cash Flows from Financing Activities                       (460,521)           (500,632)           (802,049)
                                                            -----------         -----------         -----------

Increase (Decrease) in Cash and Cash Equivalents                  4,169               8,633             (26,368)
Cash and Cash Equivalents at beginning of period                 29,235              20,602              46,970
                                                            -----------         -----------         -----------
Cash and Cash Equivalents at end of period                  $    33,404         $    29,235         $    20,602
                                                            ===========         ===========         ===========
</TABLE>

See Notes to Consolidated Financial Statements.
<PAGE>
24

Consolidated Balance Sheets

<TABLE>
<CAPTION>
At December 31,                                                      1997               1996
                                                                        Thousands of Dollars
<S>                                                           <C>                <C>        
Assets

Utility Plant
Electric - Transmission & Distribution                        $ 3,617,666        $ 3,494,778
Electric - Generation                                           1,434,895         10,127,602
Gas                                                             1,071,819          1,005,507
Common                                                            302,672            317,065
                                                              -----------        -----------
                                                                6,427,052         14,944,952
     Less Accumulated Provision for Depreciation                2,690,824          5,046,950
                                                              -----------        -----------
                                                                3,736,228          9,898,002
Nuclear Fuel, net                                                 147,359            199,579
Construction Work in Progress                                     611,204            661,871
Leased Property, net                                              175,933            182,088
                                                              -----------        -----------
     Net Utility Plant                                          4,670,724         10,941,540
                                                              -----------        -----------


Current Assets
Cash and Temporary Cash Investments                                33,404             29,235
Accounts Receivable, net
     Customers                                                    173,350             19,159
     Other                                                        139,996             74,377
Inventories, at average cost
     Fossil Fuel                                                   84,858             84,633
     Materials and Supplies                                        90,890            119,743
Deferred Generation Costs Recoverable in Current Rates            424,497                 --
Deferred Energy Costs-Gas                                          35,665             30,013
Other                                                              20,115             63,234
                                                              -----------        -----------
     Total Current Assets                                       1,002,775            420,394
                                                              -----------        -----------


Deferred Debits and Other Assets
Competitive Transition Charge                                   5,274,624                 --
Recoverable Deferred Income Taxes                                 590,267          2,325,721
Deferred Limerick Costs                                                --            361,762
Deferred Non-Pension Postretirement Benefits Costs                 97,409            233,492
Deferred Energy Costs-Electric                                         --             92,021
Investments                                                       515,835            432,574
Loss on Reacquired Debt                                            83,918            283,853
Other                                                             121,016            169,262
                                                              -----------        -----------
     Total Deferred Debits and Other Assets                     6,683,069          3,898,685
                                                              -----------        -----------

Total Assets                                                  $12,356,568        $15,260,619
                                                              ===========        ===========
</TABLE>

See Notes to Consolidated Financial Statements.


<PAGE>
                                                                              25
Consolidated Balance Sheets (Continued)

<TABLE>
<CAPTION>
At December 31,                                                     1997                 1996
                                                                         Thousands of Dollars
<S>                                                         <C>                  <C>         
Capitalization and Liabilities

Capitalization
Common Shareholders' Equity
     Common Stock                                           $  3,517,731         $  3,517,614
     Other Paid-In Capital                                         1,239                1,326
     Retained (Deficit) Earnings                                (792,239)           1,127,041
                                                            ------------         ------------
                                                               2,726,731            4,645,981
Preferred and Preference Stock
     Without Mandatory Redemption                                137,472              199,367
     With Mandatory Redemption                                    92,700               92,700
Company Obligated Mandatorily Redeemable Preferred
     Securities of a Partnership, which holds Solely
     Subordinated Debentures of the Company                      352,085              302,182
Long-Term Debt                                                 3,853,141            3,935,514
                                                            ------------         ------------
     Total Capitalization                                      7,162,129            9,175,744
                                                            ------------         ------------

Current Liabilities
Notes Payable, Bank                                              401,500              287,500
Long-Term Debt Due Within One Year                               247,087              283,303
Capital Lease Obligations Due Within One Year                     55,808               49,347
Accounts Payable                                                 306,847              212,966
Taxes Accrued                                                     66,397               71,482
Interest Accrued                                                  77,911               82,006
Dividends Payable                                                 16,969               22,407
Deferred Income Taxes                                            185,696                2,745
Other                                                            260,457               91,608
                                                            ------------         ------------
     Total Current Liabilities                                 1,618,672            1,103,364
                                                            ------------         ------------

Deferred Credits and Other Liabilities
Capital Lease Obligations                                        120,125              132,741
Deferred Income Taxes                                          2,297,042            3,745,242
Unamortized Investment Tax Credits                               318,065              336,132
Pension Obligation                                               211,596              224,454
Non-Pension Postretirement Benefits Obligation                   324,850              315,058
Other                                                            304,089              227,884
                                                            ------------         ------------
     Total Deferred Credits and Other Liabilities              3,575,767            4,981,511
                                                            ------------         ------------

Commitments and Contingencies (Notes 3, 4 and 5)

Total Capitalization and Liabilities                        $ 12,356,568         $ 15,260,619
                                                            ============         ============
</TABLE>


See Notes to Consolidated Financial Statements.

<PAGE>
26

Consolidated  Statements of Changes in Common Shareholders' Equity and Preferred
Stock


<TABLE>
<CAPTION>
                                                                      Other      Retained
                                                Common Stock         Paid-In     Earnings       Preferred Stock
All Amounts in Thousands                     Shares       Amount     Capital     (Deficit)   Shares      Amount

<S>                                         <C>        <C>           <C>        <C>           <C>      <C>     
Balance at January 1, 1995                   221,609    $3,490,728    $1,271      $810,507     3,702    $370,172
                                             -------    ----------    ------    ----------     -----    --------

Net Income                                                                         609,732
Cash Dividends Declared
     Preferred Stock
       (at specified annual rates)                                                 (24,253)
     Common Stock ($1.65 per share)                                               (366,087)
Expenses of Capital Stock Activity                                                  (4,035)
Capital Stock Activity
     Long-Term Incentive Plan Issuances          563        15,585                  (2,156)
     Preferred Stock Issuances                                            55
     Preferred Stock Redemptions                                                                (781)    (78,105)
                                             -------    ----------    ------    ----------     -----    --------
Balance at December 31, 1995                 222,172     3,506,313     1,326     1,023,708     2,921     292,067

Net Income                                                                         517,205
Cash Dividends Declared
     Preferred Stock
       (at specified annual rates)                                                 (21,042)
     Common Stock ($1.755 per share)                                              (390,527)
Expenses of Capital Stock Activity                                                    (275)
Capital Stock Activity
     Long-Term Incentive Plan Issuances          370        11,301                  (2,028)
                                             -------    ----------    ------    ----------     -----    --------
Balance at December 31, 1996                 222,542     3,517,614     1,326     1,127,041     2,921     292,067

Net Loss                                                                        (1,497,106)
Cash Dividends Declared
     Preferred Stock
       (at specified annual rates)                                                 (16,805)
     Common Stock ($1.80 per share)                                               (400,578)
Expenses of Capital Stock Activity                                                      98
Interest on Stock Repurchase
     Forward Contract                                                               (4,889)
Capital Stock Activity
     Long-Term Incentive Plan Issuances            5           117
     Preferred Stock Redemptions                                         (87)                   (619)    (61,895)
                                             -------    ----------    ------    ----------     -----    --------
Balance at December 31, 1997                 222,547    $3,517,731    $1,239     $(792,239)    2,302    $230,172
                                             =======    ==========    ======     =========     =====    ========
</TABLE>

See Notes to Consolidated Financial Statements.


<PAGE>
27

Notes to Consolidated Financial Statements


1. Significant Accounting Policies


General
The  consolidated  financial  statements  of PECO  Energy  Company  include  the
accounts of its utility  subsidiary  companies,  all of which are wholly  owned.
Accounting  policies are in accordance  with those  prescribed by the regulatory
authorities  having  jurisdiction,  principally the Pennsylvania  Public Utility
Commission  (PUC) and the  Federal  Energy  Regulatory  Commission  (FERC).  The
Company has unconsolidated  non-utility subsidiaries which are not material. The
unconsolidated subsidiaries are accounted for under the equity method.

Use of Estimates
The preparation of financial  statements in conformity  with generally  accepted
accounting principles requires management to make estimates and assumptions that
affect  the  reported  amounts  of assets  and  liabilities  and  disclosure  of
contingent  assets and  liabilities at the date of the financial  statements and
the  reported  amounts of revenues  and expenses  during the  reporting  period.
Actual results could differ from those estimates.

     Estimates are used in the Company's  accounting for unbilled  revenue,  the
allowance for uncollectible accounts,  fuel adjustment clause,  depreciation and
amortization, taxes, reserves for contingencies, employee benefits, certain fair
value and recoverability determinations, and nuclear outage costs, among others.

Accounting for the Effects of Regulation
The Company  accounts for all of its regulated  operations  in  accordance  with
Statement of Financial  Accounting  Standards (SFAS) No. 71, "Accounting for the
Effects of Certain  Types of  Regulation,"  requiring  the Company to record the
financial  statement  effects  of the rate  regulation  to which the  Company is
currently  subject.  If a separable portion of the Company's  business no longer
meets the  provisions  of SFAS No. 71, the Company is required to eliminate  the
financial  statement effects of regulation for that portion.  Effective December
31, 1997, the Company  determined  that the electric  generation  portion of its
business no longer met the criteria of SFAS No. 71 and, accordingly, implemented
SFAS No. 101,  "Regulated  Enterprises - Accounting for the  Discontinuation  of
FASB Statement No. 71," for that portion of its business (see note 4).

Revenues
Electric  and gas  revenues  are  recorded  as service is  rendered or energy is
delivered  to  customers.  At the end of each  month,  the  Company  accrues  an
estimate for the  unbilled  amount of energy  delivered or services  provided to
customers (see note 8).

Energy and Purchased Gas Cost Adjustment Clause
The  Company's  gas rates are subject to a fuel  adjustment  clause  designed to
recover or refund the  difference  between the actual cost of purchased  gas and
the amount  included in base rates.  Differences  between the amounts  billed to
customers  and the actual  costs  recoverable  are  deferred  and  recovered  or
refunded in future  periods by means of prospective  adjustments to rates.  Such
rates are adjusted quarterly.

     Prior to December  31,  1996,  the  Company's  retail  electric  rates were
subject to an Energy Cost Adjustment  (ECA) clause designed to recover or refund
the difference  between the actual cost of fuel, energy interchange or purchased
power and the amount of such costs  included in base rates.  Effective  December
31, 1996,  the PUC  approved the roll-in of electric  energy costs into the base
rates charged to the Company's  retail electric  customers and such rates are no
longer subject to the ECA.

Utility Plant
Effective December 31, 1997, electric generation plant is valued at the lower of
original cost or market pursuant to SFAS No. 121, "Accounting for the Impairment
of  Long-Lived  Assets and for  Long-Lived  Assets to Be Disposed Of." All other
utility plant continues to be valued at original cost (see note 4).

Nuclear Fuel
The cost of nuclear fuel is capitalized  and charged to fuel expense on the unit
of production  method.  Estimated  costs of nuclear fuel disposal are charged to
fuel  expense as the related fuel is consumed.  The  Company's  share of nuclear
fuel at Peach Bottom Atomic Power Station  (Peach  Bottom) and Salem  Generating
Station  (Salem) is accounted for as a capital  lease.  Nuclear fuel at Limerick
Generating Station (Limerick) is owned.

Depreciation and Decommissioning
Depreciation  is  provided  over  the  estimated  service  lives of plant on the
straight-line method. The Company is currently reviewing the useful lives of its
electric  generation  assets.  Annual  depreciation   provisions  for  financial
reporting  purposes,  expressed as a percentage of average  depreciable  utility
plant in  service,  were  approximately  3.3% in 1997,  2.9% in 1996 and 2.8% in
1995. See note 3 for  information  concerning the change in 1996 to depreciation
and amortization.

     The  Company's  current  estimate  of the  costs  for  decommissioning  its
ownership  share of its nuclear  generating  stations is  currently  included in
electric base rates and is charged to operations over the expected  service life
of the related  plant.  The amounts  recovered  from  customers are deposited in
trust  accounts and invested for funding of future  costs.  These  amounts,  and
realized investment earnings thereon, are credited to accumulated  depreciation.
The Company  believes that the amounts being  recovered from  customers  through
electric  rates will be sufficient to fully fund the  unrecorded  portion of its
decommissioning obligation (see note 5).

<PAGE>
28

Income Taxes
The Company uses an asset and liability  approach for financial  accounting  and
reporting of income taxes.  Investment tax credits are deferred and amortized to
income over the estimated useful life of the related property (see note 14).

Allowance for Funds Used During Construction (AFUDC)
AFUDC is the cost,  during the period of construction,  of debt and equity funds
used to  finance  construction  projects.  AFUDC  is  recorded  as a  charge  to
Construction  Work in Progress and as a credit to Other  Income and  Deductions.
The rates used for  capitalizing  AFUDC,  which averaged 8.88% in 1997, 9.38% in
1996 and 9.88% in 1995,  are computed  under a method  prescribed  by regulatory
authorities.   AFUDC  is  not  included  in  regular   taxable  income  and  the
depreciation of capitalized AFUDC is not tax deductible.

     Effective  January 1, 1998, the Company ceased  accruing AFUDC for electric
generation-related construction projects and will use SFAS No. 34, "Capitalizing
Interest  Costs," to calculate  the costs during the period of  construction  of
debt  funds  used  to  finance  its  electric  generation-related   construction
projects.

Nuclear Outage Costs
Incremental  nuclear maintenance and refueling outage costs are accrued over the
unit  operating  cycle.  For each  unit,  an  accrual  for  incremental  nuclear
maintenance  and  refueling  outage  expense is estimated  based upon the latest
planned outage schedule and estimated costs for the outage.  Differences between
the accrued and actual expense for the outage are recorded when such differences
are known.

Capitalized Software Costs
Software projects which exceed $5 million are capitalized.  At December 31, 1997
and 1996,  capitalized  software  costs  totaled $86 and $78 million (net of $29
million accumulated amortization in each year),  respectively.  Such capitalized
amounts are amortized  ratably over the expected lives of the projects when they
become operational, not to exceed ten years.

Gains and Losses on Reacquired Debt
Prior to December 31, 1997,  gains and losses on  reacquired  debt were deferred
and  amortized  to interest  expense  over the period  approved  for  ratemaking
purposes.  Effective  January  1,  1998,  gains and  losses on  reacquired  debt
associated with the electric generation portion of the Company's operations will
be expensed as incurred. Gains and losses on reacquired debt associated with the
Company's  regulated  operations  will  continue to be deferred and amortized to
interest expense over the period approved for ratemaking purposes.

Reclassifications
Certain  prior-year  amounts have been  reclassified  for comparative  purposes.
These  reclassifications  had no  effect on net  income or common  shareholders'
equity.


2. Nature of Operations and Segment Information

The Company  provides  retail  electric and natural gas service to the public in
southeastern  Pennsylvania and, in pilot programs,  natural gas service to areas
in Maryland and New Jersey. The Company also engages in the wholesale  marketing
of electricity on a national basis.  The Company  participates in joint ventures
which  provide  telecommunications   services  in  the  Philadelphia  area.  The
Company's  traditional  retail  service  territory  covers 2,107  square  miles.
Electric service is furnished to an area of 1,972 square miles with a population
of 3.6 million, including 1.6 million in the City of Philadelphia. Approximately
94% of the retail  electric  service area and 64% of retail  kilowatthour  (kWh)
sales are in the suburbs around Philadelphia,  and 6% of the retail service area
and 36% of such sales are in the City of  Philadelphia.  Natural  gas service is
supplied in a 1,475-square-mile  area of southeastern  Pennsylvania  adjacent to
Philadelphia with a population of 1.9 million.

<TABLE>
<CAPTION>
For the Years Ended December 31,                         1997               1996                1995
                                                                                Thousands of Dollars
<S>                                               <C>                <C>                 <C>        
Electric Operations
Operating revenues:
Residential                                       $ 1,357,449        $ 1,370,158         $ 1,379,046
Small commercial and industrial                       778,743            748,561             730,220
Large commercial and industrial                     1,077,374          1,098,307           1,135,550
Other                                                 147,523            140,133             136,988
Unbilled                                               19,130            (25,950)             42,580
                                                  -----------        -----------         -----------
     Service territory                              3,380,219          3,331,209           3,424,384
Interchange sales                                      58,614             25,991              17,488
Sales to other utilities                              727,836            497,636             333,454
                                                  -----------        -----------         -----------
     Total operating revenues                       4,166,669          3,854,836           3,775,326
                                                  -----------        -----------         -----------
Operating expenses, excluding depreciation          2,697,877          2,243,094           2,026,112
Depreciation                                          552,667            462,315             430,993
                                                  -----------        -----------         -----------
     Operating income                             $   916,125        $ 1,149,427         $ 1,318,221
                                                  ===========        ===========         ===========
Utility plant additions                           $   382,157        $   447,105         $   435,400
                                                  ===========        ===========         ===========
</TABLE>

<PAGE>
                                                                              29
<TABLE>
<CAPTION>
For the Years Ended December 31,                          1997                 1996                 1995
                                                                                    Thousands of Dollars
<S>                                               <C>                  <C>                  <C>         
Gas Operations
Operating revenues:
Residential                                       $     16,852         $     15,716         $     15,482
House heating                                          265,299              249,507              235,456
Commercial and industrial                              144,801              132,822              125,631
Other                                                    3,228               11,462                5,382
Unbilled                                                  (969)              (4,250)               6,540
                                                  ------------         ------------         ------------
     Subtotal                                          429,211              405,257              388,491
                                                  ------------         ------------         ------------
Other revenues (including transported
     for customers)                                     22,021               23,557               22,339
                                                  ------------         ------------         ------------
     Total operating revenues                          451,232              428,814              410,830
                                                  ------------         ------------         ------------
Operating expenses, excluding depreciation             333,798              303,054              301,994
Depreciation                                            27,928               26,686               26,261
                                                  ------------         ------------         ------------
     Operating income                             $     89,506         $     99,074         $     82,575
                                                  ============         ============         ============
Utility plant additions                           $     85,212         $     68,394         $     63,192
                                                  ============         ============         ============

Identifiable Assets* at December 31,
Electric                                          $  9,610,984         $ 10,287,444         $ 10,408,105
Gas                                                    966,685              858,471              785,881
Nonallocable assets                                  1,778,899            4,114,704            4,114,519
                                                  ------------         ------------         ------------
     Total assets                                 $ 12,356,568         $ 15,260,619         $ 15,308,505
                                                  ============         ============         ============
</TABLE>

*    Includes   utility  plant  less  accumulated   depreciation,   inventories,
     segment-specific regulatory assets and allocated common utility property.

3. Rate Matters

Competition Act
The Electricity Generation Customer Choice and Competition Act (Competition Act)
was enacted in December 1996,  providing for the  restructuring  of the electric
utility  industry in Pennsylvania,  including retail  competition for generation
beginning in 1999.  The  Competition  Act requires  the  unbundling  of electric
services into separate generation,  transmission and distribution  services with
open retail competition for generation.  Electric  distribution and transmission
services  will  remain  regulated  by the  PUC.  The  Competition  Act  requires
utilities to submit to the PUC restructuring plans, including  quantification of
their   stranded   costs   (the  loss  in  value  of  the   Company's   electric
generation-related assets, which will result from competition).  The Competition
Act authorizes the recovery of stranded  costs through  charges to  distribution
customers for up to nine years (or for an alternative  period  determined by the
PUC for good cause shown).  During that period, the utility is subject to a rate
cap which provides that total charges to customers  cannot exceed rates in place
as of December 31, 1996, subject to certain exceptions. The Competition Act also
caps transmission and distribution rates from December 31, 1996 through June 30,
2001, subject to certain exceptions.

     Pursuant to the Competition  Act, in April 1997, the Company filed with the
PUC a comprehensive  restructuring plan detailing its proposal to implement full
customer choice of electric  generation  supplier.  The Company's  restructuring
plan  identified $7.5 billion of stranded costs. In August 1997, the Company and
various intervenors in the Company's restructuring proceeding filed with the PUC
a Joint Petition for Partial Settlement (Pennsylvania Plan).

     In December  1997,  the PUC rejected the  Pennsylvania  Plan and entered an
Opinion  and Order,  revised in January  1998 (PUC  Restructuring  Order),  that
deregulates the Company's electric generation operations.  The PUC Restructuring
Order allows the Company to recover $4.9 billion on a discounted  basis, or $5.3
billion on a book value basis,  over 8-1/2 years beginning in 1999.  Recovery of
allowed  stranded  costs will be through a separate  charge to be levelized over
the recovery period using a 7.47% cost of capital. Other major provisions of the
PUC  Restructuring  Order include  capping  customer  bills at the year-end 1996
system-wide average of 9.95 cents per kWh; beginning January 1, 1999, unbundling
rates into a transmission and distribution component, the charge for recovery of
stranded costs and a "shopping credit" for generation;  and phasing-in  customer
choice  of  electric  generation  supplier  for all  customers  in three  steps:
one-third of the peak load of each customer class on January 1, 1999,  one-third
on  January 2, 1999 (one day later)  and the  remainder  on January 2, 2000.  To
encourage competition,  the PUC established the "shopping credit" for generation
in excess of current market prices.

     On January 21, 1998,  the Company  filed a complaint  in the U.S.  District
Court for the Eastern District of Pennsylvania  seeking  injunctive and monetary
relief on the grounds that the Competition Act and the PUC Restructuring  Order:
(1) are  preempted  by Section  201(b) of the  Federal  Power Act;  (2) effect a
taking of private property  without just  compensation in violation of the Fifth
and Fourteenth Amendments to the U.S. Constitution;  (3) violate the Due Process
Clause,  the Contract Clause and the First  Amendment of the U.S.  Constitution;
and (4) deprive the Company of certain other federally protected rights.
<PAGE>
30

     On January 22,  1998,  the Company  filed two  Petitions  for Review in the
Commonwealth Court of Pennsylvania,  appealing the PUC Restructuring  Order. The
petitions state that the PUC Restructuring Order must be set aside because it is
based upon errors of law, is not supported by substantial evidence,  constitutes
an arbitrary and capricious abuse of administrative  discretion and deprives the
Company of the due process of law, to which it is  entitled  under  Article I of
the Pennsylvania Constitution.

Limerick
Under its electric tariffs through December 31, 1997, the Company was recovering
$285  million of  deferred  Limerick  costs  representing  carrying  charges and
depreciation associated with 50% of Limerick common facilities. The Company also
deferred certain  operating and maintenance  expenses,  depreciation and accrued
carrying  charges on its capital  investment  in Limerick  Unit No. 2 and 50% of
Limerick  common  facilities.  These costs were  included in base rates and were
being recovered over a nine-year period  beginning  October 1, 1996. The Company
was also  recovering  $137 million of Limerick  Unit No. 1 costs over a ten-year
period  without a return on investment.  At December 31, 1997,  the  unamortized
portion  of  these   regulatory   assets  were  included  as  part  of  electric
generation-related regulatory assets (see note 4).

     Under its  electric  tariffs and ECA, the Company was allowed to retain for
shareholders  any  proceeds  above  the  average  energy  cost for  sales of 399
megawatts (MW) of near-term  excess  capacity  and/or  associated  energy and to
share in the benefits  which  resulted from the operation of both Limerick Units
No. 1 and No. 2. The Company's ECA was discontinued at December 31, 1996. During
1996 and 1995,  the  Company  recorded  as revenue net of fuel costs $82 and $79
million,  respectively, as a result of the sale of the 399 MW of capacity and/or
associated energy and the Company's share of Limerick energy savings.


Declaratory Accounting Order
Pursuant to a PUC  Declaratory  Order,  effective  October 1, 1996,  the Company
increased  depreciation and  amortization on assets  associated with Limerick by
$100  million per year and  decreased  depreciation  and  amortization  on other
Company assets by $10 million per year, for a net increase in  depreciation  and
amortization of $90 million per year.  Effective  December 31, 1997, the Company
ceased  this  increased  depreciation  since  this  Declaratory  Order  has been
superseded by the PUC Restructuring Order. At December 31, 1997, the $90 million
of  depreciation  and  amortization  that would have been recognized in 1998 was
deferred as a regulatory  asset,  since the Company's  rates will continue to be
cost-based until January 1, 1999, and will be amortized and recovered in 1998.

Recovery of Non-Pension Postretirement Benefits Costs
Effective January 1995, the Company increased electric base rates by $25 million
per year to recover the increased  costs,  including the annual  amortization of
the transition  obligation (over 18 years) deferred in 1994 and 1993, associated
with  the   implementation   of  SFAS  No.  106,   "Employers'   Accounting  for
Postretirement  Benefits  Other Than  Pensions,"  (see note 7).  During 1997 and
1996, the Company deposited $26 and $47 million, respectively, in trust accounts
to fund its retail electric  non-pension  postretirement  benefits costs.  These
costs include  amounts charged to operating  expense or capitalized  during 1997
and 1996.  At  December  31,  1997,  $121  million  of the  previously  recorded
transition  obligation  was  included  as  part of  electric  generation-related
regulatory assets (see note 4).

     The Company recognizes $2.8 million in non-pension  postretirement benefits
costs annually associated with gas utility operations. During 1997 and 1996, the
Company deposited $2.8 and $2.9 million, respectively, in trust accounts to fund
its gas non-pension postretirement benefits costs.

Energy Cost Adjustment
Through December 31, 1996, the Company was subject to a PUC-established electric
ECA which,  in addition to reconciling  fuel costs and revenues,  incorporated a
nuclear  performance  standard which allowed for financial  bonuses or penalties
depending on whether the Company's  system nuclear  capacity  factor exceeded or
fell below a specified  range.  For the years ended  December 31, 1996 and 1995,
the Company recorded bonuses of $22 and $13 million, respectively.

4.   Accounting Changes

The Company accounts for all of its regulated operations in accordance with SFAS
No. 71 which allows the Company to record the financial statement effects of the
rate  regulation  to  which  the  Company  is  subject.  Use of SFAS  No.  71 is
applicable  to the utility  operations  of the Company  which meet the following
criteria:  (1) third-party  regulation of rates; (2) cost-based rates; and (3) a
reasonable  assumption that all costs will be recoverable from customers through
rates.

     In 1997,  the  Financial  Accounting  Standards  Board  (FASB)  through its
Emerging  Issues Task Force (EITF)  issued EITF No. 97-4,  "Deregulation  of the
Pricing of  Electricity - Issues Related to the  Application of FASB  Statements
No. 71, Accounting for the Effects of Certain Types of Regulation,  and No. 101,
Regulated  Enterprises - Accounting  for the  Discontinuation  of Application of
FASB Statement No. 71." The EITF agreed that: a) an entity should cease to apply
SFAS No. 71 no later than the date the specific deregulation plan is enacted and
the details of that plan are known,  and b) both  stranded  costs and  regulated
assets and  liabilities  should continue to be recognized to the extent that the
transition plan provides for their recovery  through the regulated  transmission
and distribution portion of the business.

     The Company believes that the PUC Restructuring  Order provides  sufficient
details  regarding  the  deregulation  of  the  Company's  electric   generation
operations to require the Company to discontinue  the application of SFAS No. 71
for those  operations.  Effective  December  31, 1997,  the Company  adopted the
provisions of SFAS No. 101 for its electric generation operations.  SFAS No. 101
requires a  determination  of impairment of plant assets under SFAS No. 121, and
the  elimination of all effects of rate  regulation that have been recognized as
assets and liabilities pursuant to SFAS No. 71.
<PAGE>
                                                                              31

     At December  31, 1997,  the Company  performed  an  impairment  test of its
electric  generation  assets  pursuant to SFAS No. 121 on a plant specific basis
and  determined  that $6.1  billion of its $7.1  billion of electric  generation
assets would be impaired as of December 31, 1998. The Company estimated the fair
value for each of its electric  generating  units by  determining  its estimated
future  operating cash inflows and outflows.  The net future cash flows for each
electric  generating  plant were then  compared to its net book  value.  For any
electric generating plant with future undiscounted cash flows less than its book
value,  net cash flows were discounted using a discount rate  commensurate  with
the risk of each electric  generating plant. Since the Company's retail electric
rates will  continue  to be  cost-based  until  January 1,  1999,  $0.3  billion
representing depreciation expense on electric  generation-related assets in 1998
has been  reclassified to a regulatory asset and will be amortized and recovered
in 1998.

     At  December   31,   1997,   the  Company  had  $2.7  billion  of  electric
generation-related  regulatory  assets,  of which $0.1 billion will be amortized
and recovered through cost-based rates in 1998.

     At December 31,  1997,  the Company had total  electric  generation-related
stranded  costs of $8.4  billion,  representing  $5.8  billion  of net  stranded
electric  generation  plant  and $2.6  billion  of  electric  generation-related
regulatory  assets.  The PUC  Restructuring  Order allows the Company to recover
$4.9 billion on a discounted  basis,  or $5.3 billion on a book-value  basis, of
its  generation-related  stranded  costs from  customers.  This results in a net
unrecoverable amount of $3.1 billion.

     Although the Company is appealing the PUC Restructuring  Order,  Management
believes   that  EITF  No.  97-4   required   it  to  write  off  all   electric
generation-related  stranded costs for which recovery through rates has not been
provided.  Accordingly, the Company recorded an extraordinary charge at December
31,   1997  of  $3.1   billion   ($1.8   billion   net  of  taxes)  of  electric
generation-related stranded costs that will not be recovered from customers.

     A summary,  as of December  31, 1997,  of the  electric  generation-related
stranded costs and the amount of such stranded costs  written-off by the Company
is shown in the following table:

                                                     (Thousands of Dollars)
Electric generation-related asset impairment determined
     pursuant to SFAS No. 121
Net book value of electric
     generation-related assets
     before write-down                                          $7,115,155 
December 31, 1998 market value of
     electric generation-related assets
     pursuant to SFAS No. 121                                     (990,376)
Expected 1998 change in net plant
     recognized for recovery until
     cost-based rates cease at
     December 31, 1998                                            (303,800)
                                                                ---------- 
Electric generation-related asset impairment                     5,820,979

Electric generation-related regulatory assets

Recoverable Deferred Income Taxes                                1,762,946
Deferred Limerick Costs                                            321,420
Deferred Non-Pension Postretirement
     Benefits Other Than Pensions                                  120,899
Deferred Energy Costs - Electric                                    92,021
Loss on Reacquired Debt                                            177,183
Additional assets written-off pursuant to
     discontinuance of SFAS No. 71                                 104,818
Other                                                               90,480
Regulatory asset recognized for
     recovery until cost-based
     rates cease at December 31, 1998                              (91,497)
                                                                ---------- 
Total electric generation-related regulatory assets              2,578,270
                                                                ---------- 

Total electric generation-related stranded costs                 8,399,249

Amounts approved for collection
     from customers (regulatory asset
     pursuant to EITF No. 97-4)                                 (5,274,624)
                                                                ---------- 

Total Extraordinary Item                                       $ 3,124,625
                                                                ========== 


     Due to the market-based  pricing of electric  generation  provisions of the
PJM Interconnection, L.L.C. restructuring order approved by the FERC in November
1997,  the Company  believes that its wholesale  energy sales  operations are no
longer  subject to the  provisions of SFAS No. 71. Based on  projections  of the
Company's  retail load growth,  the Company believes all of its owned generation
capacity  is  necessary  to meet its  electric  retail  load.  As a result,  the
discontinuance  of SFAS No. 71 for its wholesale energy sales operations has not
resulted in an additional charge against income.

     The Company believes that its electric transmission and distribution system
and gas  operations  continue to meet the provisions of SFAS No. 71. The Company
believes  that it is  probable  that  regulatory  assets  associated  with these
operations will be recovered.
<PAGE>
32

     The Company  has  adopted  SFAS No.  128,  "Earnings  Per Share,"  which is
designed to simplify the existing computational  guidelines for the earnings per
share  (EPS)  information  provided  in  financial  statements,  to  revise  the
disclosure  requirements  and to increase  the  comparability  of EPS data on an
international  basis.  Pursuant to SFAS No. 128,  the Company  reflected  on its
Consolidated Statements of Income basic EPS and dilutive EPS for the years ended
December  31, 1997,  1996 and 1995.  Adoption of SFAS No. 128 did not impact the
amount of EPS reported and there is no difference  in the amounts  calculated as
basic EPS and dilutive EPS.

5. Commitments and Contingencies

Capital Commitments
Total capital  expenditures,  primarily for utility  plant,  are estimated to be
$600  million  in  1998.  Due  to  the  expected   adverse  impact  of  the  PUC
Restructuring  Order and  competition  for electric  generating  services on its
future  capital  resources,  the  Company is  currently  evaluating  its capital
commitments for 1999 and beyond. Certain facilities under construction and to be
constructed  may require permits and licenses which the Company has no assurance
will  be  granted.  The  Company  has  undertaken  a  number  of  new  ventures,
principally  through  its  Telecommunications   Group,  some  of  which  require
significant  cash  commitments.   For  1998,  the  Company's   expected  capital
expenditures include approximately $150 million in such ventures.

     The  Company's  operations  have in the past and may in the future  require
substantial capital expenditures in order to comply with environmental laws.

Nuclear Insurance
The  Price-Anderson Act currently limits the liability of nuclear reactor owners
to $8.9 billion for claims that could arise from a single incident. The limit is
subject to change to account  for the  effects of  inflation  and changes in the
number  of  licensed  reactors.   The  Company  carries  the  maximum  available
commercial  insurance of $200 million and the remaining $8.7 billion is provided
through  mandatory  participation  in a  financial  protection  pool.  Under the
Price-Anderson  Act,  all nuclear  reactor  licensees  can be assessed up to $79
million  per  reactor  per  incident,  payable at no more than $10  million  per
reactor per incident per year. This assessment is subject to inflation and state
premium taxes. In addition,  Congress could impose revenue  raising  measures on
the nuclear industry to pay claims.

     The  Company  carries  property  damage,   decontamination   and  premature
decommissioning insurance in the amount of its $2.75 billion proportionate share
for each station loss resulting from damage to its nuclear plants.  In the event
of an accident,  insurance proceeds must first be used for reactor stabilization
and site decontamination.  If the decision is made to decommission the facility,
a portion  of the  insurance  proceeds  will be  allocated  to a fund  which the
Company is required by the Nuclear Regulatory  Commission (NRC) to maintain,  to
provide for decommissioning  the facility.  The Company is unable to predict the
timing  of the  availability  of  insurance  proceeds  to the  Company  for  the
Company's bondholders, and the amount of such proceeds which would be available.
Under  the terms of the  various  insurance  agreements,  the  Company  could be
assessed  up to $26  million  for losses  incurred  at any plant  insured by the
insurance  companies.  The Company is self-insured to the extent that any losses
may exceed the amount of insurance maintained. Such losses could have a material
adverse effect on the Company's financial condition and results of operations.

     The  Company is a member of an  industry  mutual  insurance  company  which
provides  replacement  power cost  insurance in the event of a major  accidental
outage at a nuclear  station.  The  premium  for this  coverage  is  subject  to
assessment  for adverse loss  experience.  The  Company's  maximum  share of any
assessment is $13 million per year.

Nuclear Decommissioning and Spent Fuel Storage
The Company's current estimate of its nuclear facilities'  decommissioning  cost
of $1.5 billion in 1997 dollars is being collected  through  electric rates over
the life of each  generating  unit.  Beginning  in 1999,  these  amounts will be
recoverable  through  transmission and distribution  rates. Under current rates,
the Company  collects  and  expenses  approximately  $20 million  annually  from
customers.  The expense is accounted for as a component of depreciation  expense
and  accumulated  depreciation.  At December  31,  1997 and 1996,  $294 and $256
million,  respectively,  was included in accumulated  depreciation.  In order to
fund future  decommissioning  costs,  at December 31, 1997 and 1996, the Company
held $320 and $266 million,  respectively,  in trust accounts which are included
as an Investment in the  Company's  Consolidated  Balance Sheet and include both
net unrealized and realized gains.  Net unrealized  gains of $43 and $26 million
were recognized as a Deferred Credit in the Company's Consolidated Balance Sheet
at December 31, 1997 and 1996, respectively. The Company recognized net realized
gains of $11, $10 and $9 million as Other Income in the  Company's  Consolidated
Statement  of Income  for the years  ended  December  31,  1997,  1996 and 1995,
respectively.  The  Company  believes  that the  amounts  being  recovered  from
customers through electric rates will be sufficient to fully fund the unrecorded
portion of its decommissioning obligation.

     In an  Exposure  Draft  issued in 1996,  the FASB  proposed  changes in the
accounting for closure and removal costs of production facilities, including the
recognition, measurement and classification of decommissioning costs for nuclear
generating  stations.  The FASB has expanded the scope of the Exposure  Draft to
include closure or removal  liabilities that are incurred at any time during the
operating  life of the related  long-lived  asset.  The FASB has decided that it
should proceed toward either a final Statement or a revised  Exposure Draft. The
timing of this project is still to be determined.  If current  electric  utility
industry accounting practices for decommissioning are changed, annual provisions
for  decommissioning  could increase and the estimated cost for  decommissioning
could be recorded as a liability  rather than as accumulated  depreciation  with
recognition of an increase in the cost of a related regulatory asset.

     Under the Nuclear Waste Policy Act of 1982 (NWPA),  the U.S.  Department of
Energy (DOE) is required to begin taking  possession  of all spent  nuclear fuel
generated by the Company's  nuclear units for long-term storage by no later than
1998. Based on recent public  pronouncements,  it is not 


<PAGE>
                                                                              33

likely that a permanent  disposal site will be available for the industry before
2015,  at the earliest.  In reaction to statements  from the DOE that it was not
legally  obligated  to begin to accept  spent fuel in 1998, a group of utilities
and state government  agencies filed a lawsuit against the DOE which resulted in
a decision by the U.S. Court of Appeals for the District of Columbia (D.C. Court
of Appeals) in July 1996 that the DOE had an unequivocal  obligation to begin to
accept spent fuel in 1998. In accordance with the NWPA, the Company pays the DOE
one mill  ($.001) per  kilowatthour  of net nuclear  generation  for the cost of
nuclear fuel disposal. This fee may be adjusted prospectively in order to ensure
full cost  recovery.  Because of inaction by the DOE following the D.C. Court of
Appeals finding of the DOE's obligation to begin receiving spent fuel in 1998, a
group of forty-two utility companies, including the Company, and forty-six state
agencies,  filed suit against the DOE seeking  authorization  to suspend further
payments to the U.S. government under the NWPA and to deposit such payments into
an escrow account until such time as the DOE takes effective  action to meet its
1998 obligations.  In November 1997, the D.C. Court of Appeals issued a decision
in which it held that the DOE had not abided by its prior determination that the
DOE has an  unconditional  obligation to begin disposal of spent nuclear fuel by
January  31,  1998.  The  D.C.  Court of  Appeals  also  precluded  the DOE from
asserting that it was not required to begin receiving spent nuclear fuel because
it had not yet prepared a permanent  repository or an interim storage  facility.
The  DOE  and  one  of  the  utility   companies   have  filed  a  Petition  for
Reconsideration of the decision.  The U.S. House of Representatives and the U.S.
Senate passed  separate bills in 1997  authorizing  construction  of a temporary
storage  facility  which could accept spent nuclear fuel from utilities in 2003.
In addition,  the DOE is exploring  other options to address delays in the waste
acceptance schedule.

     Peach Bottom has on-site  facilities  with  capacity to store spent nuclear
fuel discharged from the units through 2000 for Unit No. 2 and 2001 for Unit No.
3.  Life-of-plant  storage capacity will be provided by on-site dry cask storage
facilities,  the construction of which will begin in 1998.  Limerick has on-site
facilities with capacity to store spent nuclear fuel to 2007.  Salem has on-site
facilities with spent fuel storage capacity through 2008 for Unit No. 1 and 2012
for Unit No. 2. Public Service  Electric and Gas Company (PSE&G) is the operator
of Salem, which is 42.59% owned by the Company.

Energy Commitments
The Company's  electric utility  operations  include the wholesale  marketing of
electricity. At December 31,1997, the Company had long-term commitments relating
to the purchase from  unaffiliated  utilities and others energy  associated with
1,330 MW of capacity in 1998,  with 2,540 MW of capacity  during the period 1999
through 2002 and with 2,430 MW of capacity  thereafter.  During 1997,  purchases
under long-term  commitments  resulted in  expenditures  of $311 million.  As of
December 31, 1997, these purchases  result in commitments of approximately  $240
million  for  1998,  $620  million  for  1999  through  2002  and  $830  million
thereafter.  These purchases will be utilized  through a combination of sales to
jurisdictional  customers,  long-term  sales to other  utilities and open market
sales. Under some of these contracts,  the Company may purchase,  at its option,
additional power as needed.

     In the  wholesale  market,  the  Company has  increased  its sales to other
utilities, but increased competition has reduced the Company's profit margins on
these  sales.  At December  31,  1997,  the Company had entered  into  long-term
agreements with  unaffiliated  utilities to sell energy associated with 4,280 MW
of capacity,  of which 540 MW of these agreements are for 1998, 1,700 MW are for
1999 through 2002 and the remaining 2,040 MW extend through 2022.

Environmental Issues
The  Company'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,  the  Company  is
generally  liable for the costs of remediating  environmental  contamination  of
property now or formerly  owned by the Company and of property  contaminated  by
hazardous  substances  generated  by the  Company.  The Company 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 which are
considered hazardous under environmental laws. The Company 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.

     The Company has  identified  27 sites where former  manufactured  gas plant
(MGP)  activities  have or may have resulted in actual site  contamination.  The
Company is presently engaged in performing various levels of activities at these
sites, including initial evaluation to determine the existence and nature of the
contamination,  detailed evaluation to determine the extent of the contamination
and the necessity and possible  methods of remediation,  and  implementation  of
remediation.   The  Pennsylvania  Department  of  Environmental  Protection  has
approved  the  Company's  clean-up of two sites.  Six other sites are  currently
under some degree of active study and/or remediation.

     As of  December  31,  1997 and 1996,  the  Company  had accrued $63 and $28
million,  respectively,  for environmental  investigation and remediation costs,
including  $35  and  $16  million,   respectively,  for  MGP  investigation  and
remediation,  that  currently can be reasonably  estimated.  The Company  cannot
predict  whether it will incur  other  significant  liabilities  for  additional
investigation  and remediation  costs at these or additional sites identified by
the  Company,  environmental  agencies or others,  or whether such costs will be
recoverable from third parties.

Shutdown of Salem Generating Station
PSE&G removed Salem Units No. 1 and No. 2 from service in the second  quarter of
1995 and informed the NRC at that time that it had  determined to keep the Salem
units  shut  down  pending  review  and  resolution  of  certain  equipment  and
management  issues and NRC agreement that each unit is sufficiently  prepared to
restart.  Unit No. 2 returned to service on August 30, 1997, and PSE&G estimates
the  restart of Unit No. 1 to occur late in the first  quarter of 1998.  For the
years ended December 31, 1997, 1996 and 1995, the Company  incurred and expensed
approximately $152, $149 and $50 million of  shutdown-related  replacement power
and maintenance costs, respectively (see note 21).
<PAGE>
34

Telecommunications
The Company  periodically  reviews its  investments  to determine  that they are
properly valued in its financial  statements.  Due to circumstances  involved in
the Federal Communication Commission's auctioning of the personal communications
systems "C-block"  licenses,  the Company has determined that $20 million of its
telecommunications  investments were impaired at December 31, 1997. Accordingly,
at December 31, 1997,  the Company  incurred a $20 million  charge against Other
Income and Deductions to write off this telecommunications investment.

Litigation
The  Company is involved  in various  other  litigation  matters.  The  ultimate
outcome of such  matters,  while  uncertain,  is not expected to have a material
adverse effect on the Company's financial condition or results of operations.

6. Retirement Benefits

The Company and its subsidiaries  have a  non-contributory  trusteed  retirement
plan applicable to all regular employees.  The benefits are based primarily upon
employees'  years of service  and  average  earnings  prior to  retirement.  The
Company's funding policy is to contribute,  at a minimum,  amounts sufficient to
meet the Employee  Retirement  Income Security Act  requirements.  Approximately
89%, 80% and 74% of pension costs were charged to  operations in 1997,  1996 and
1995,  respectively,  and the remainder,  associated with construction labor, to
the cost of new utility plant.

Pension costs for 1997, 1996 and 1995 included the following components:

<TABLE>
<CAPTION>
                                                           1997              1996              1995
                                                                               Thousands of Dollars
<S>                                                   <C>               <C>               <C>      
Service cost benefits earned during the period        $  25,368         $  27,627         $  19,710
Interest cost on projected benefit obligation           150,057           145,570           147,261
Actual return on plan assets                           (377,803)         (320,247)         (456,057)
Amortization of transition asset                         (4,538)           (4,538)           (4,538)
Amortization and deferral                               197,480           154,402           300,214
                                                      ---------         ---------         ---------
     Net pension cost                                 $  (9,436)        $   2,814         $   6,590
                                                      =========         =========         =========
</TABLE>

The  changes  in net  periodic  pension  costs  in 1997,  1996 and 1995  were as
follows:

<TABLE>
<CAPTION>
                                                              1997             1996             1995
Thousands of Dollars
<S>                                                       <C>              <C>              <C>     
Change in number, characteristics and salary
     levels of participants and net actuarial gain        $ (7,839)        $(12,893)        $  1,486
Change in plan provisions                                    3,118               --           (8,305)
Change in actuarial assumptions                             (7,529)           9,117           (3,136)
                                                          --------         --------         --------
     Net change                                           $(12,250)        $ (3,776)        $ (9,955)
                                                          ========         ========         ========
</TABLE>

Plan assets consist principally of common stock, U.S. government obligations and
other fixed  income  instruments.  In  determining  pension  costs,  the assumed
long-term rate of return on assets was 9.5% for 1997, 1996 and 1995.

     The  weighted-average  discount  rate  used in  determining  the  actuarial
present  value of the  projected  benefit  obligation  was 7.25% at December 31,
1997,  7.75% at December 31, 1996 and 7.25% at December  31,  1995.  The average
rate of increase in future  compensation levels ranged from 4% to 6% at December
31, 1997, 1996 and 1995.

       Prior service cost is amortized on a straight-line basis over the average
remaining  service  period of employees  expected to receive  benefits under the
plan.


<PAGE>
                                                                              35

The funded  status of the plan at December  31, 1997 and 1996 is  summarized  as
follows:

<TABLE>
<CAPTION>
                                                                              1997                1996
Thousands of Dollars
<S>                                                                     <C>                 <C>        
Actuarial present value of accumulated plan benefit obligations:
Vested benefit obligation                                               $ 1,794,222         $ 1,657,098
Accumulated benefit obligation                                            1,890,848           1,742,116

Projected benefit obligation for services rendered to date              $ 2,141,040         $ 1,982,915
Plan assets at fair value                                                (2,538,039)         (2,302,935)
                                                                        -----------         -----------
     Funded status                                                         (396,999)           (320,020)
Unrecognized transition asset                                                35,713              40,251
Unrecognized prior service costs                                            (83,188)            (92,682)
Unrecognized net gain                                                       649,903             588,013
                                                                        -----------         -----------
     Pension obligation recognized on the balance sheet                 $   205,429         $   215,562
                                                                        ===========         ===========
</TABLE>


7. Non-Pension Postretirement Benefits

The Company provides certain health care and life insurance benefits for retired
employees.  Company  employees become eligible for these benefits if they retire
from the Company with ten years of service.  These benefits and similar benefits
for active  employees are provided by an insurance  company  whose  premiums are
based upon the benefits paid during the year.

     The transition  obligation,  which  represents the previously  unrecognized
accumulated non-pension postretirement benefit obligation, is being amortized on
a straight-line  basis over an allowed 20-year period. At December 31, 1997, the
Company   accelerated   recognition   of  $121   million   of  its   non-pension
postretirement benefits obligation related to its electric generation operations
and  included  this  regulatory  asset  as part of  electric  generation-related
regulatory assets (see note 4).

     The  transition  obligation  was  determined by application of the terms of
medical,  dental and life insurance plans,  including the effects of established
maximums on covered  costs,  together with relevant  actuarial  assumptions  and
health care cost trend rates, which are projected to range from 7% in 1998 to 5%
in 2002.  The effect of a 1% annual  increase in these  assumed cost trend rates
would increase the accumulated  postretirement benefit obligation by $85 million
and the annual service and interest costs by $10 million.

     Total  costs for all plans were $73 million in 1997 and $71 million in 1996
and 1995.

     The net  periodic  benefits  costs for  1997,  1996 and 1995  included  the
following components:
<TABLE>
<CAPTION>
                                                          1997             1996             1995
                                                                            Thousands of Dollars
<S>                                                   <C>              <C>              <C>     
Service cost benefits earned during the period        $ 14,401         $ 11,855         $  8,681
Interest cost on projected benefit obligation           54,149           48,524           48,641
Amortization of transition asset                        14,882           14,882           14,882
Actual return on plan assets                           (22,691)         (13,257)          (2,075)
Deferred asset gain                                     12,707            9,320            1,359
                                                      --------         --------         --------
     Net postretirement benefits costs                $ 73,448         $ 71,324         $ 71,488
                                                      ========         ========         ========
</TABLE>

Plan assets consist principally of common stock, U.S. government obligations and
other  fixed  income  instruments.  In  determining  non-pension  postretirement
benefits costs, the assumed  long-term rate of return on assets was 8% for 1997,
1996 and 1995.

     The  weighted-average  discount  rate  used in  determining  the  actuarial
present value of the  projected  benefit  obligation  was 7.75% as of January 1,
1997, 7.50% as of January 1, 1996 and 8.50% at January 1, 1995. The average rate
of increase in future  compensation  levels ranged from 4% to 6% at December 31,
1997, 1996 and 1995.

     Prior service cost is amortized on a  straight-line  basis over the average
remaining  service  period of employees  expected to receive  benefits under the
plan.
<PAGE>

The funded  status of the plan at December  31, 1997 and 1996 is  summarized  as
follows:
<TABLE>
<CAPTION>
                                                               1997              1996
Thousands of Dollars
<S>                                                       <C>               <C>      
Accumulated postretirement benefit obligation:
Retirees                                                  $ 697,084         $ 609,206
Fully eligible active plan participants                       8,875             4,509
Other active plan participants                               73,272            48,986
                                                          ---------         ---------
     Total                                                  779,231           662,701
Plan assets at fair value                                  (178,045)         (126,661)
                                                          ---------         ---------
     Accumulated postretirement benefit obligation
       in excess of plan assets                             601,186           536,040
Unrecognized transition obligation                         (223,226)         (238,108)
Unrecognized net gain                                       (53,110)           17,126
                                                          ---------         ---------
     Accrued postretirement benefits obligation
       recognized on the balance sheet                    $ 324,850         $ 315,058
                                                          =========         =========
</TABLE>

Measurement of the accumulated postretirement benefits obligation was based on a
7.25%  and  7.75%  assumed  discount  rate as of  December  31,  1997 and  1996,
respectively.


8. Accounts Receivable

Accounts  receivable at December 31, 1997 and 1996 included  unbilled  operating
revenues of $135 and $117 million, respectively. Accounts receivable at December
31, 1997 and 1996 were net of an allowance for uncollectible accounts of $32 and
$24 million, respectively.

     The  Company  has  adopted  SFAS No. 125,  "Accounting  for  Transfers  and
Servicing  of  Financial  Assets  and  Extinguishments  of  Liabilities,"  which
provides a standard for  distinguishing  between  transfers of financial  assets
that are  accounted  for as sales from those that are  accounted  for as secured
borrowings.

     The Company is party to an  agreement  with a financial  institution  under
which it can sell or  finance  with  limited  recourse  an  undivided  interest,
adjusted daily, in up to $425 million of designated  accounts  receivable  until
November  2000.  At December  31,  1997,  the  Company  had sold a $425  million
interest  in  accounts  receivable,  consisting  of a $296  million  interest in
accounts  receivable which the Company accounts for as a sale under SFAS No. 125
and a $129 million interest in special agreement accounts  receivable which were
accounted for as a long-term note payable (see note 12). The Company retains the
servicing responsibility for these receivables.

9. Common Stock

At December  31, 1997 and 1996,  common  stock  without par value  consisted  of
500,000,000   shares   authorized  and  222,546,562   and   222,542,087   shares
outstanding,  respectively.  At December 31, 1997,  there were 5,800,841  shares
reserved  for  issuance  under the  Company's  Dividend  Reinvestment  and Stock
Purchase Plan.

Stock Repurchase

During 1997, the Company's Board of Directors authorized the repurchase of up to
25 million  shares of its common  stock from time to time  through  open-market,
privately  negotiated  and/or other types of transactions in conformity with the
rules of the Securities and Exchange Commission.

     Pursuant to these  authorizations,  the Company  has entered  into  forward
purchase  agreements to be settled from time to time, at the Company's election,
on either a  physical,  net share or net cash  basis.  The amount at which these
agreements can be settled is dependent  principally upon the market price of the
Company's  common stock as compared to the forward  purchase price per share and
the number of shares to be settled.  If these  agreements  had been settled on a
net  share  basis  at  December  31,  1997,  based on the  closing  price of the
Company's   common  stock  on  that  date,   the  Company  would  have  received
approximately 1,160,000 shares of Company common stock.

Long-Term Incentive Plan (LTIP)

The Company  maintains an LTIP for certain full-time  salaried  employees of the
Company.  The types of long-term  incentive awards which have been granted under
the LTIP are  non-qualified  options to purchase shares of the Company's  common
stock,  dividend  equivalents and shares of restricted common stock. The Company
uses the disclosure-only provisions of SFAS No. 123, "Accounting for Stock-Based
Compensation."  
<PAGE>
                                                                              37

If the Company  elected to account for the LTIP based on SFAS No. 123,  earnings
applicable to common stock and earnings per average common share would have been
changed to the pro forma amounts as follows:

<TABLE>
<CAPTION>
                                                                                1997          1996
                                                                              Thousands of Dollars
<S>                                                  <C>              <C>                 <C>
Earnings applicable to common stock                    As reported       $(1,513,910)     $499,169
                                                       Pro forma         $(1,515,895)     $497,887

Earnings per average common share (Dollars)            As reported         $   (6.80)     $   2.24
                                                       Pro forma           $   (6.81)     $   2.24
</TABLE>

Options  granted  under the LTIP become  exercisable  one year after the date of
grant and all  options  expire 10 years from the date of the grant.  Information
with  respect to the LTIP at  December  31, 1997 and changes for the three years
then ended, is as follows:

<TABLE>
<CAPTION>
                                                Weighted                  Weighted                  Weighted
                                                 Average                   Average                   Average
                                                Exercise                  Exercise                  Exercise
                                                   Price                     Price                     Price
                                   Shares    (per share)      Shares    (per share)       Shares  (per share)
                                     1997          1997         1996          1996          1995        1995

<S>                           <C>           <C>           <C>         <C>            <C>         <C>      
Balance at January 1            2,961,194      $   26.68   2,591,765     $   26.16     2,651,397   $   26.73
Options granted                 1,139,000          22.49     786,500         28.12       850,700       26.46
Options exercised                      --          --       (369,871)        25.07      (561,232)      23.91
Options cancelled                (283,400)         24.96     (47,200)        29.36      (349,100)      35.57
                                ---------                  ---------                   ---------
Balance at December 31          3,816,794          26.14   2,961,194         26.68     2,591,765       26.16
                                ---------                  ---------                   ---------
Exercisable at
  December 31                   2,800,794          26.65   2,192,694         26.17     1,813,565       25.91
Weighted average fair
  value of options granted
  during year                                  $    2.97                 $    2.78                 $    2.91
</TABLE>


The fair value of each  option is  estimated  on the date of the grant using the
Black-Scholes   option-pricing   model  with  the  following   weighted  average
assumptions used for grants in 1997, 1996 and 1995, respectively:

                                   1997           1996           1995

Dividend yield                      6.2%           6.2%           6.2%
Expected volatility                19.5%          16.6%          15.3%
Risk-free interest rate             6.4%           5.5%           6.9%
Expected life (years)                 5              5              5


At December 31, 1997, the option groups  outstanding based on ranges of exercise
prices is as follows:


<TABLE>
<CAPTION>
                                            Options Outstanding                       Options Exercisable
                                                      Weighted-
                                                        Average     Weighted                    Weighted-
                                                      Remaining      Average                      Average
                                     Number    Contractual Life     Exercise         Number      Exercise
Range of Exercise Prices        Outstanding             (Years)        Price    Exercisable         Price
<S>                             <C>                    <C>        <C>            <C>         <C>     
$15.75 - $20.00                    156,094                4.47       $ 18.65        117,594     $  18.43
$20.01 - $25.00                    863,500                8.23         22.35        153,000        22.66
$25.01 - $30.00                  2,607,000                6.72         27.32      2,518,000        27.22
$30.01 - $50.00                    190,200                9.58         33.27         12,200        37.18
                                 ---------                                       ---------
     Total                       3,816,794                                       2,800,794
                                 =========                                       =========
</TABLE>


<PAGE>
38

10. Preferred and Preference Stock

At December 31, 1997 and 1996,  Series Preference Stock consisted of 100,000,000
shares authorized, of which no shares were outstanding. At December 31, 1997 and
1996,  cumulative Preferred Stock, no par value,  consisted of 15,000,000 shares
authorized.

<TABLE>
<CAPTION>
                              Current               Shares                         Amount
                           Redemption            Outstanding                Thousands of Dollars
                             Price(a)         1997           1996            1997            1996
Series (without mandatory
     redemption)
<S>                           <C>      <C>             <C>           <C>            <C>        
$4.68                         104.00       150,000        150,000      $   15,000     $    15,000
$4.40                         112.50       274,720        274,720          27,472          27,472
$4.30                         102.00       150,000        150,000          15,000          15,000
$3.80                         106.00       300,000        300,000          30,000          30,000
$7.96                             --            --        618,954              --          61,895
$7.48                             (b)      500,000        500,000          50,000          50,000
                                       -----------      ---------      ----------      ----------
                                         1,374,720      1,993,674         137,472         199,367
Series (with mandatory
     redemption)
$6.12                             (c)      927,000        927,000          92,700          92,700
                                       -----------      ---------      ----------      ----------
     Total preferred stock             $ 2,301,720      2,920,674      $  230,172      $  292,067
                                       ===========      =========      ==========      ==========
<FN>
(a)  Redeemable,  at the option of the Company,  at the indicated dollar amounts
     per share, plus accrued dividends.
(b)  None of the shares of this series are subject to redemption  prior to April
     1, 2003.
(c)  There are no annual sinking fund  requirements in 1998. Annual sinking fund
     requirements  in 1999 - 2003 are  $18,540,000.  None of the  shares of this
     series are subject to redemption prior to August 1, 1999.
</FN>
</TABLE>


11.  Company Obligated Mandatorily Redeemable Preferred Securities of a
     Partnership (COMRPS)

At  December  31, 1997 and 1996,  PECO Energy  Capital,  L.P.  (Partnership),  a
Delaware  limited  partnership of which a wholly owned subsidiary of the Company
is the sole general partner, had outstanding three and two series, respectively,
of cumulative  COMRPS,  each with a liquidation value of $25 per security.  Each
series  is  supported  by  the  Company's   deferrable   interest   subordinated
debentures,  held by the Partnership,  which bear interest at rates equal to the
distribution  rates on the  securities.  The interest paid by the Company on the
debentures  is  included  in Other  Income and  Deductions  in the  Consolidated
Statements of Income and is deductible for income tax purposes.

<TABLE>
<CAPTION>
                    Mandatory                         Trust Receipts                     Amount
                   Redemption  Distribution             Outstanding               Thousands of Dollars
At December 31,          Date          Rate            1997          1996            1997           1996
Series
<S>                    <C>        <C>             <C>           <C>           <C>              <C>      
A                      2043       9.00%           8,850,000     8,850,000     $   221,250      $ 221,250
B (a)                  2025       8.72%           3,124,183     3,124,183          80,835         80,932
C (b)                  2037       8.00%           2,000,000            --          50,000             --
                                                 ----------    ----------       ---------      ---------
     Total                                       13,974,183    11,974,183       $ 352,085      $ 302,182
                                                 ==========    ==========       =========      =========
<FN>
(a)  Ownership of this series is evidenced by Trust Receipts,  each representing
     an 8.72% COMRPS, Series B, representing limited partnership interests.  The
     Trust  Receipts were issued by PECO Energy Capital Trust I, the sole assets
     of which are 8.72%  COMRPS,  Series B.  Each  holder of Trust  Receipts  is
     entitled to withdraw the  corresponding  number of 8.72%  COMRPS,  Series B
     from the Trust in exchange for the Trust Receipts so held.

(b)  Ownership of this series is evidenced by Trust Receipts,  each representing
     an 8.00% COMRPS, Series C, representing limited partnership interests.  The
     Trust Receipts were issued by PECO Energy Capital Trust II, the sole assets
     of which are 8.00%  COMRPS,  Series C.  Each  holder of Trust  Receipts  is
     entitled to withdraw the  corresponding  number of 8.00%  COMRPS,  Series C
     from the Trust in exchange for the Trust Receipts so held.
</FN>
</TABLE>


<PAGE>
                                                                              39
<TABLE>
<CAPTION>
12. Long-Term Debt
At December 31,                                Series             Due               1997           1996
                                                                                   Thousands of Dollars
<S>                                       <C>                 <C>            <C>              <C> 
First and refunding mortgage bonds (a)            6 1/8%            1997     $        --    $    75,000
                                                  5 3/8%            1998         225,000        225,000
                                           7 1/2%-9 1/4%            1999         325,000        325,000
                                           5 5/8%-7 3/8%            2001         330,000        330,000
                                               7 1/8%-8%            2002         500,000        500,000
                                          6 3/8%-10 1/4%       2003-2007         565,625        569,688
                                                     (b)       2008-2012         154,200        154,200
                                           6 5/8%-8 3/4%       2018-2022         832,130        832,130
                                           7 1/8%-7 3/4%       2023-2024         775,000        775,000
                                                                             -----------    -----------
Total first and refunding mortgage bonds                                       3,706,955      3,786,018
Notes payable                                                                     15,574             --
Term loan agreements                                 (c)            1997              --        175,000
Pollution control notes                              (d)       2016-2034         212,705        212,705
Medium-term notes                                    (e)       1998-2005          62,400         74,400
Note Payable - accounts receivable agreement         (f)            2000         128,999             --
Unamortized debt discount and premium, net                                       (26,405)       (29,306)
                                                                             -----------    -----------
Total long-term debt                                                           4,100,228      4,218,817
Due within one year                                  (g)                         247,087        283,303
                                                                             -----------    -----------
     Long-term debt included in capitalization       (h)                     $ 3,853,141    $ 3,935,514
                                                                             ===========    ===========

<FN>
(a)  Utility plant is subject to the lien of the Company's mortgage.
(b)  Floating rates, which were an average annual interest rate of 3.725% at
     December 31, 1997.
(c)  The Company has a $900 million unsecured revolving credit facility with a
     group of banks. The credit facility is composed of a $450 million 364-day
     credit agreement and a $450 million three-year credit agreement. The
     Company uses the credit facility principally to support the Company's
     commercial paper program, which was expanded from $300 million to $600
     million in 1997. There was no debt outstanding under this credit facility
     at December 31, 1997.
(d)  Floating rates, which were an average annual interest rate of 3.75% at
     December 31, 1997.
(e)  Medium-term notes collateralized by mortgage bonds. The average annual
     interest rate was 8.75% at December 31, 1997.
(f)  See note 8.
(g)  Long-term debt maturities, including mandatory sinking fund requirements,
     in the period 1998-2002 are as follows: 1998 - $247,087,409; 1999 -
     $361,945,982; 2000 - $137,129,159; 2001 - $338,433,453; 2002 -
     $508,759,067.
(h)  The annualized interest on long-term debt at December 31, 1997, was $286
     million, of which $269 million was associated with mortgage bonds and $17
     million was associated with other long-term debt.
</FN>
</TABLE>

13. Short-Term Debt
<TABLE>
<CAPTION>
                                                                       1997          1996           1995
                                                                                    Thousands of Dollars
<S>                                                             <C>             <C>           <C>       
Average borrowings                                              $   248,111     $ 198,090     $   17,560
Average interest rates, computed on daily basis                        5.83%         5.64%         6.25%
Maximum borrowings outstanding                                  $   464,500      $369,500      $ 182,000
Average interest rates, at December 31                                 6.74%         6.90%            --
</TABLE>

The Company has a $600 million  commercial  paper  program which is supported by
the $900 million  revolving credit facility (see note 12). At December 31, 1997,
$314 million of  commercial  paper was  outstanding.  At December 31, 1997,  the
Company  had formal and  informal  lines of credit  with banks  aggregating  $75
million.  At December 31, 1997, no short-term debt was  outstanding  under these
lines.

<PAGE>
40

14. Income Taxes

Income tax expense (benefit) is comprised of the following components:
<TABLE>
<CAPTION>
<S>                                                               <C>           <C>            <C>      
For the Years Ended December 31,                                       1997          1996           1995
                                                                         Thousands of Dollars
Included in operations:
Federal
     Current                                                     $  251,509     $ 126,471      $ 190,796
     Deferred                                                       (11,378)      154,564        167,526
     Investment tax credit, net                                     (18,201)      (15,979)       (21,679)
State
     Current                                                         76,689        62,839         79,086
     Deferred                                                        (5,850)       12,206         15,988
                                                                 ----------     ---------      ---------
                                                                    292,769       340,101        431,717
                                                                 ==========     =========      =========

Included in extraordinary item:
Federal
     Current                                                           (123)            -              -
     Deferred                                                      (987,234)            -              -
State
     Current                                                            (29)            -              -
     Deferred                                                      (303,575)            -              -
                                                                 ----------     ---------      ---------
                                                                 (1,290,961)            -              -
                                                                 ----------     ---------      ---------
     Total                                                       $ (998,192)    $ 340,101      $ 431,717
                                                                 ==========     =========      =========
</TABLE>

The total income tax provisions, excluding the extraordinary item, differed from
amounts  computed  by  applying  the  federal  statutory  tax rate to  income as
follows:
<TABLE>
<CAPTION>
                                                                       1997          1996           1995
                                                                                    Thousands of Dollars
<S>                                                              <C>          <C>            <C>        
Net Income                                                       $  336,558    $  517,205     $  609,732
Total income tax provisions                                         292,769       340,101        431,717
                                                                 ----------    ----------     ----------
     Income before income taxes                                  $  629,327    $  857,306     $1,041,449
                                                                 ==========    ==========     ==========

Income taxes on above at federal statutory rate
     of 35%                                                      $  220,264    $  300,057     $  364,507
Increase (decrease) due to:
Property basis differences                                           40,828         9,903         11,196
State income taxes, net of federal income tax benefit                46,046        48,779         61,799
Amortization of investment tax credit                               (18,201)      (15,979)       (13,604)
Prior period income taxes                                            (2,985)       (1,707)         1,791
Other, net                                                            6,817          (952)         6,028
                                                                 ----------    ----------     ----------
     Total income tax provisions                                 $  292,769    $  340,101     $  431,717
                                                                 ==========    ==========     ==========
Effective income tax rate                                             46.5%         39.7%          41.5%
</TABLE>

<PAGE>
                                                                              41

Provisions for deferred income taxes consist of the tax effects of the following
temporary differences:
<TABLE>
<CAPTION>
                                                                       1997          1996           1995
                                                                                    Thousands of Dollars
<S>                                                               <C>           <C>            <C>      
Depreciation and amortization                                     $  57,530     $  42,385      $  32,287
Deferred energy costs                                                 2,256        27,374         30,073
Retirement and separation programs                                  (12,734)       19,746         15,733
Incremental nuclear outage costs                                       (981)        2,440          8,079
Uncollectible accounts                                               (1,710)       (2,805)        (1,991)
Reacquired debt                                                      (8,607)       (9,578)        (3,266)
Unbilled revenue                                                     (5,110)        3,910             (5)
Environmental clean-up costs                                        (15,121)         (714)         2,433
Obsolete inventory                                                   (7,074)        5,829          6,362
Limerick plant disallowances and phase-in plan                         (747)         (747)         2,507
AMT credits                                                               -        83,010         91,399
Other nuclear operating costs                                        (9,892)            -              -
Other                                                               (15,038)       (4,080)           (97)
                                                                -----------      --------       --------
     Subtotal                                                       (17,228)      166,770        183,514
Extraordinary item                                               (1,290,809)            -              -
                                                                -----------      --------       --------
     Total                                                      $(1,308,037)     $166,770       $183,514
                                                                ===========      ========       ========
</TABLE>

The tax  effect  of  temporary  differences  giving  rise to the  Company's  net
deferred tax liability as of December 31, 1997 and 1996 is as follows:

<TABLE>
<CAPTION>
                                                                          Liability or (Asset)
                                                                        1997               1996
                                                                          Thousands of Dollars
<S>                                                               <C>                <C>        
Nature of temporary difference:
Plant basis difference                                            $ 2,620,254        $ 3,795,786
Deferred investment tax credit                                        318,065            336,132
Deferred debt refinancing costs                                       111,651            120,031
Other, net                                                           (249,167)          (167,830)
                                                                  -----------        -----------
     Deferred income taxes (net) on the balance sheet             $ 2,800,803        $ 4,084,119
                                                                  ===========        ===========
</TABLE>

The net deferred tax liability shown above as of December 31, 1997 and 1996 is
comprised of $3,153 and $4,347 million of deferred tax liabilities, and $352 and
$263 million of deferred tax assets, respectively.

     In accordance with SFAS No. 71, the Company recorded a recoverable deferred
income  tax asset of $586 and  $2,322  million  at  December  31,1997  and 1996,
respectively.  The December 31, 1997 balance was applicable only to non-electric
generation  assets,  due to the  discontinuance of SFAS No. 71 for the Company's
electric generation operations.  These recoverable deferred income taxes include
the deferred tax effects  associated  principally with liberalized  depreciation
accounted for in accordance with the ratemaking  policies of the PUC, as well as
the revenue impacts thereon, and assume recovery of these costs in future rates.
At December 31, 1997, $1,763 million of electric generation-related  recoverable
deferred  income  taxes were  included  as part of  electric  generation-related
regulatory assets (see note 4).

     The  Internal   Revenue   Service  (IRS)  has  completed  and  settled  its
examinations of the Company's  federal income tax returns through 1986. The 1987
through 1990 federal  income tax returns have been  examined and the Company and
the IRS have reached a tentative settlement which would not result in an adverse
impact on the Company.  The years 1991 through 1993 are currently being examined
by the IRS.

     The AMT credit was fully  utilized  for tax  purposes at December 31, 1997,
and reduced federal income taxes currently payable by $6 million in 1997.

<PAGE>
42

15. Taxes, Other Than Income - Operating

<TABLE>
<CAPTION>
For the Years Ended December 31,                                  1997            1996              1995
                                                                                    Thousands of Dollars
<S>                                                           <C>             <C>               <C>     
Gross receipts                                                $163,552        $160,246          $165,172
Capital stock                                                   48,085          41,972            42,444
Real estate                                                     69,597          69,185            71,600
Payroll                                                         25,976          27,585            30,109
Other                                                            2,881             558             4,746
                                                              --------        --------          --------
     Total                                                    $310,091        $299,546          $314,071
                                                              ========        ========          ========
</TABLE>


16. Leases

Leased property included in utility plant was as follows:

<TABLE>
<CAPTION>
At December 31,                                                    1997                  1996
                                                                         Thousands of Dollars
<S>                                                           <C>                   <C>      
Nuclear fuel                                                  $ 521,921             $ 527,116
Electric plant                                                    2,321                 2,069
                                                              ---------             ---------
Gross leased property                                           524,242               529,185
Accumulated amortization                                       (348,309)             (347,097)
                                                              ---------             ---------
     Net leased property                                      $ 175,933             $ 182,088
                                                              =========             =========
</TABLE>

Nuclear  fuel is  amortized  as the fuel is  consumed.  Amortization  of  leased
property totaled $39, $31 and $43 million for the years ended December 31, 1997,
1996 and 1995,  respectively.  Other  operating  expenses  included  interest on
capital  lease  obligations  of $9 million in 1997 and 1996,  and $10 million in
1995.

Minimum future lease payments as of December 31, 1997 were:

<TABLE>
<CAPTION>
For the Years Ending December 31,                          Capital Leases     Operating Leases      Total
                                                                                     Thousands of Dollars
<S>                                                            <C>              <C>            <C>       
1998                                                           $   69,820       $  50,584      $  120,404
1999                                                               68,530          49,370         117,900
2000                                                               43,827          45,923          89,750
2001                                                               10,892          43,219          54,111
2002                                                                   92          42,327          42,419
Remaining years                                                       806         537,645         538,451
                                                               ----------     -----------      ----------
Total minimum future lease payments                            $  193,967     $   769,068      $  963,035
                                                                              ===========      ==========
Imputed interest (rates ranging from 6.5% to 17.0%)               (18,034)
                                                               ----------
   Present value of net minimum future lease payments          $  175,933
                                                               ==========
</TABLE>

Rental expense under operating  leases totaled $74 million in 1997 and 1996, and
$115 million in 1995.

<PAGE>

                                                                              43

17. Jointly Owned Electric Utility Plant

The Company's  ownership  interests in jointly owned  electric  utility plant at
December 31, 1997 were as follows:
<TABLE>
<CAPTION>
                                                                                              Transmission
                                                         Production Plants                   and Other Plant
                                Peach Bottom             Salem      Keystone     Conemaugh
                                                Public Service           GPU           GPU
                                 PECO Energy      Electric and    Generating    Generating        Various
Operator                             Company       Gas Company         Corp.         Corp.      Companies
<S>                                   <C>                <C>           <C>          <C>      <C>    
Participating interest                42.49%             42.59%        20.99%       20.72%    21% to 43%
Company's share (Thousands of Dollars)
Utility plant                     $  307,029         $   18,331    $  110,661   $  184,037    $   81,072
Accumulated depreciation             175,304             11,134        66,487       78,605        31,273
Construction work in progress         50,028                713        10,067        9,100         1,943
</TABLE>

The Company's  participating interests are financed with Company funds and, when
placed in service,  all  operations  are accounted for as if such  participating
interests were wholly owned facilities.

18. Cash and Cash Equivalents

For purposes of the Statements of Cash Flows,  the Company  considers all highly
liquid debt instruments  purchased with a maturity of three months or less to be
cash  equivalents.   The  following  disclosures   supplement  the  accompanying
Statements of Cash Flows:

<TABLE>
<CAPTION>
                                                      1997            1996           1995
                                                                     Thousands of Dollars
<S>                                               <C>             <C>            <C>     
Cash paid during the year:
     Interest (net of amount capitalized)         $405,838        $415,063       $449,664
     Income taxes (net of refunds)                 345,232         251,554        257,677
Noncash investing and financing:
     Capital lease obligations incurred             32,909          33,063         48,760
</TABLE>

19. Investments

<TABLE>
<CAPTION>
At December 31,                                                    1997             1996
                                                                    Thousands of Dollars
<S>                                                            <C>              <C>     
Trust accounts for decommissioning nuclear plants              $320,442         $266,270
Telecommunications ventures                                      85,601           79,833
Energy services and other ventures                               65,578           44,023
Nonutility property                                              24,697           26,349
Other                                                            19,517           16,099
                                                               --------         --------
     Total                                                     $515,835         $432,574
                                                               ========         ========
</TABLE>

20. Financial Instruments

Fair values of financial instruments, including liabilities, are estimated based
on quoted market prices for the same or similar issues. The carrying amounts and
fair values of the Company's  financial  instruments as of December 31, 1997 and
1996 were as follows:
<TABLE>
<CAPTION>
Thousands of Dollars                                                     1997                   1996
                                                                Carrying        Fair     Carrying        Fair
                                                                  Amount       Value       Amount       Value
                                                                                  
<S>                                                              <C>         <C>         <C>          <C>    
Cash and temporary cash investments                              $33,404     $33,404     $29,235      $29,235
Long-term debt (including amounts due within one year)         4,100,228   4,210,885   4,218,817    4,239,357
Trust accounts for decommissioning nuclear plants                320,442     320,442     266,270      266,270
</TABLE>

Financial instruments which potentially subject the Company to concentrations of
credit risk consist  principally  of  temporary  cash  investments  and customer
accounts  receivable.  The Company  places its temporary cash  investments  with
high-credit quality financial institutions. At times, such investments may be in
excess of the Federal Deposit  Insurance  Corporation  limit.  Concentrations of
credit risk with respect to customer accounts  receivable are limited due to the
Company's large number of customers and their dispersion across many industries.
<PAGE>
44

21. Other Income

Settlement of Salem Litigation
On December 31, 1997, the Company  received $70 million pursuant to the May 1997
settlement agreement with PSE&G resolving a suit filed by the Company concerning
the shutdown of Salem. The agreement also provides that if the outage exceeds 64
reactor  unit  months,  PSE&G will pay the Company $1 million  per reactor  unit
month.  As of December 31, 1997,  the shutdown of Salem  totaled 58 reactor unit
months. During the second quarter of 1997, the Company recorded $70 million ($41
million net of income taxes) as Other Income.

Sale of Subsidiary
In June 1995,  the Company  completed  the sale of  Conowingo  Power  Company to
Delmarva Power & Light Company (Delmarva) for $150 million. The transaction also
included a ten-year  contract  for the  Company to sell power to  Delmarva.  The
Company's  gain of $59  million  ($27  million  net of  taxes)  on the  sale was
recorded in the second quarter of 1995.

22. Regulatory Assets and Liabilities

At December 31, 1997 and 1996, the Company had deferred the following regulatory
assets on the Consolidated Balance Sheet:
<TABLE>
<CAPTION>
                                                                   1997             1996
                                                                    Thousands of Dollars
<S>                                     <C>                  <C>         <C>            
Competitive transition charge (see note 4)                   $5,274,624       $        -
Recoverable deferred income taxes (see note 14)                 585,661        2,321,692
Deferred generation costs recoverable in current
   rates (see note 4)                                           424,497                -
Deferred Limerick costs (see note 3)                                 -           361,762
Loss on reacquired debt                                          83,918          283,853
Compensated absences                                              3,881           37,727
Deferred energy costs (see note 3)                               35,665          122,034
Non-pension postretirement benefits (see note 3)                 97,409          233,492
                                                             ----------       ----------
     Total                                                   $6,505,655       $3,360,560
                                                             ==========       ==========
</TABLE>

23. Quarterly Data (Unaudited)

The data  shown  below  include  all  adjustments  which the  Company  considers
necessary for a fair presentation of such amounts:
<TABLE>
<CAPTION>
                                 Operating Revenues          Operating Income     Net Income (Loss)
Millions of Dollars                1997         1996         1997        1996       1997       1996
<S>                               <C>          <C>         <C>         <C>        <C>        <C>   
Quarter ended
March 31                          $1,163       $1,171      $  302      $  357     $  113     $  150
June 30                            1,032          989         250         267        123         99
September 30                       1,278        1,110         388         347        158        150
December 31                        1,144        1,014          66         278     (1,891)       118
</TABLE>
<TABLE>
<CAPTION>
                              Earnings Applicable             Average Shares              Earnings
                                to Common Stock                 Outstanding           Per Average Share

Millions of Dollars             1997       1996               1997       1996         1997       1996
<S>                             <C>        <C>               <C>        <C>          <C>        <C>   
Quarter ended
March 31                        $109       $146              222.5      222.4        $ 0.49     $ 0.65
June 30                          118         94              222.5      222.5          0.53       0.43
September 30                     154        145              222.5      222.5          0.69       0.65
December 31                   (1,895)       114              222.5      222.5         (8.51)      0.51
</TABLE>
The decrease in 1997 first quarter  results was primarily due to increased  fuel
and energy  interchange  expense resulting  primarily from additional  purchases
needed for increased sales to other utilities and higher replacement power costs
due to the Salem outage,  milder  weather and increased  depreciation  of assets
associated with Limerick.

     The increase in 1997 second quarter results was primarily due to the
recognition of the settlement of litigation arising from the Salem outage.
Offsetting this increase was higher depreciation of assets associated with
Limerick.

     The decrease in 1997 fourth quarter results was primarily due to the
extraordinary charge of $8.24 per share resulting from the effects of the PUC
Restructuring Order and deregulation of the Company's electric generation
operations; several one-time adjustments for changes in employee benefits,
write-offs of information systems development charges reflecting clarification
of accounting guidelines and additional reserves to revise estimates for
accruals; higher income tax adjustments; and higher losses from the Company's
non-utility ventures.
<PAGE>

                                                                             45

Financial Statistics

Summary of Earnings and Financial Condition
<TABLE>
<CAPTION>
For the Years Ended December 31,                1997        1996        1995         1994          1993       1992
                                                                                               Millions of Dollars
<S>                                           <C>        <C>         <C>          <C>           <C>        <C>    
Income Data
Operating Revenues                            $4,618     $ 4,284     $ 4,186      $ 4,041       $ 3,988    $ 3,963
Operating Income                               1,006       1,249       1,401        1,064         1,390      1,298
Income before Extraordinary Item                 337         517         610          427           591        479
Extraordinary Item (net of income taxes)      (1,834)          -           -            -             -          -
Net Income                                    (1,497)        517         610          427           591        479
Earnings Applicable to Common
     Stock Before Extraordinary Item          (1,514)        499         587          389           542        418

Earnings per Average Common Share
     Before Extraordinary Item (Dollars)        1.44        2.24        2.64         1.76          2.45       1.90
Extraordinary Item (Per Share)                 (8.24)          -           -            -             -          -
Earnings per Average Common Share              (6.80)       2.24        2.64         1.76          2.45       1.90
Dividends per Common Share (Dollars)            1.80       1.755        1.65        1.545          1.43      1.325
Common Stock Equity (Per Share)                12.25       20.88       20.40        19.41         19.25      18.24
Average Shares of Common Stock
     Outstanding (Millions)                    222.5       222.5       221.9        221.6         221.1      220.2

At December 31,

Balance Sheet Data
Net Utility Plant                             $4,495     $10,760     $10,758      $10,829       $10,763    $10,691
Leased Property, net                             176         182         181          174           194        210
Total Current Assets                           1,003         420         426          427           515        550
Total Deferred Debits and
     Other Assets                              6,683       3,899       3,944        3,992         3,905      1,127
                                             -------     -------     -------      -------       -------    -------
     Total Assets                            $12,357     $15,261     $15,309      $15,422       $15,377    $12,578
                                             =======     =======     =======      =======       =======    =======

Common Shareholders' Equity                  $ 2,727     $ 4,646     $ 4,531      $ 4,303       $ 4,263    $ 4,022
Preferred and Preference Stock
     Without Mandatory Redemption                137         199         199          277           423        423
     With Mandatory Redemption                    93          93          93           93           187        231
Company Obligated Mandatorily
     Redeemable Preferred
     Securities of a Partnership                 352         302         302          221            --         --
Long-term Debt                                 3,853       3,936       4,199        4,786         4,884      5,204
                                             -------     -------     -------      -------       -------    -------
     Total Capitalization                      7,162       9,176       9,324        9,680         9,757      9,880
Total Current Liabilities                      1,619       1,103       1,052          850           954        830
Total Deferred Credits and
     Other Liabilities                         3,576       4,982       4,933        4,892         4,666      1,868
                                             -------     -------     -------      -------       -------    -------
     Total Capitalization and
          Liabilities                        $12,357     $15,261     $15,309      $15,422       $15,377    $12,578
                                             =======     =======     =======      =======       =======    =======
</TABLE>
<PAGE>
46

Operating Statistics
<TABLE>
<CAPTION>
For the Years Ended December 31,              1997         1996         1995         1994          1993       1992

Electric Operations
<S>                                          <C>         <C>          <C>          <C>           <C>         <C>  
Output (Millions of Kilowatthours)
Fossil                                       9,659       10,856       10,792       11,239        10,352      8,082
Nuclear                                     25,853       24,373       25,499       28,195        27,026     24,428
Hydro                                        1,558        2,404        1,425        1,970         1,699      1,803
Pumped storage output                        1,403        1,540        1,741        1,596         1,478      1,597
Pumped storage input                        (1,924)      (2,230)      (2,507)      (2,256)       (2,192)    (2,217)
Purchase and interchange                    29,615       19,539       13,945        6,164         6,447      8,675
Internal combustion                            144          179          175          106            56         29
                                         ---------    ---------    ---------    ---------     ---------  ---------
     Total electric output                  66,308       56,661       51,070       47,014        44,866     42,397
                                         =========    =========    =========    =========     =========  =========
Sales (Millions of Kilowatthours)
Residential                                 10,407       10,671       10,636       10,859        10,609      9,965
Small commercial and industrial              6,685        6,491        6,200        6,150         5,769      5,396
Large commercial and industrial             15,034       15,208       15,763       15,968        15,956     15,829
Other                                          841          902          860          791           771        962
Unbilled                                        70         (327)         535         (205)           31       (159)
                                         ---------    ---------    ---------    ---------     ---------  ---------
     Service territory                      33,037       32,945       33,994       33,563        33,136     31,993
Interchange sales                            1,927          935          496          768           457      1,231
Sales to other utilities                    28,893       20,243       14,041       10,039         8,670      6,699
                                         ---------    ---------    ---------    ---------     ---------  ---------
     Total electric sales                   63,857       54,123       48,531       44,370        42,263     39,923
                                         =========    =========    =========    =========     =========  =========
Number of Customers, December 31,
Residential                              1,333,861    1,324,448    1,321,379    1,350,210     1,341,873  1,333,926
Small commercial and industrial            144,142      142,431      141,653      143,605       142,363    141,253
Large commercial and industrial              3,308        3,299        3,394        3,603         3,742      3,972
Other                                        1,094        1,051          959          944           888        857
                                         ---------    ---------    ---------    ---------     ---------  ---------
     Total electric customers            1,482,405    1,471,229    1,467,385    1,498,362     1,488,866  1,480,008
                                         =========    =========    =========    =========     =========  =========
Operating Revenues (Millions of Dollars)
Residential                              $   1,357    $   1,370    $   1,379    $   1,371     $   1,351  $   1,308
Small commercial and industrial                779          749          730          710           679        672
Large commercial and industrial              1,077        1,098        1,135        1,149         1,168      1,225
Other                                          148          140          137          136           161        168
Unbilled                                        19          (26)          43          (11)           (1)        (7)
                                         ---------    ---------    ---------    ---------     ---------  ---------
     Service territory                       3,380        3,331        3,424        3,355         3,358      3,366
Interchange sales                               59           26           17           23            14         32
Sales to other utilities                       728          498          334          247           233        199
                                         ---------    ---------    ---------    ---------     ---------  ---------
     Total electric revenues                 4,167        3,855        3,775        3,625         3,605      3,597
                                         ---------    ---------    ---------    ---------     ---------  ---------

Operating Expenses

Operating expenses,
     excluding depreciation                  2,698        2,244        2,026        2,209         1,894      1,990
Depreciation                                   553          462          431          416           401        391
                                         ---------    ---------    ---------    ---------     ---------  ---------
     Total operating expenses                3,251        2,706        2,457        2,625         2,295      2,381
                                         ---------    ---------    ---------    ---------     ---------  ---------
Electric Operating Income                 $    916     $  1,149     $  1,318     $  1,000      $  1,310   $  1,216
                                         =========    =========    =========    =========     =========  =========

Average Use per Residential
  Customer (Kilowatthours)
Without electric heating                     6,695        6,771        6,908        6,736         6,727      6,259
With electric heating                       16,400       17,946       17,189       17,527        17,096     16,298
Total                                        7,830        8,074        8,130        8,041         7,970      7,443

Electric Peak Load, Demand
     (Thousands of Kilowatts)                7,390        6,509        7,244        7,227         7,100      6,617
Net Electric Generating Capacity-
     Year-end Summer Rating
     (Thousands of Kilowatts)                9,204        9,201        9,078        8,956         8,877      8,836
Cost of Fuel per Million BTU              $   0.84     $   0.93     $   0.87      $  0.89      $  0.90   $   0.82
BTU per Net Kilowatthour Generated          10,737       10,682       10,705       11,617        10,675     10,657
</TABLE>
<PAGE>

                                                                             47

Operating Statistics (continued)

<TABLE>
<CAPTION>
For the Years Ended December 31,              1997         1996         1995         1994          1993       1992

Gas Operations
<S>                                          <C>          <C>          <C>          <C>           <C>        <C>  
Sales (Millions of Cubic Feet)
Residential                                  1,614        1,681        1,516        1,636         1,637      1,819
House heating                               32,666       35,471       30,698       32,246        30,242     30,218
Commercial and industrial                   19,830       20,999       18,464       19,762        18,635     19,026
Other                                          673        2,571        1,582        7,039         9,733      4,885
Unbilled                                       212       (1,306)       1,710         (474)          676       (736)
                                           -------      -------      -------      -------       -------    -------
     Total gas sales                        54,995       59,416       53,970       60,209        60,923     55,212
Gas transported for customers               30,412       27,891       48,531       29,801        22,946     22,060
                                           -------      -------      -------      -------       -------    -------
     Total gas sales and
     gas transported                        85,407       87,307      102,501       90,010        83,869     77,272
                                           =======      =======      =======      =======       =======    =======

Number of Customers
Residential                                 55,592       56,003       56,533       57,122        59,573     59,859
House heating                              314,335      303,996      295,481      287,481       277,500    269,577
Commercial and industrial                   35,215       34,182       33,308       32,292        31,573     30,956
                                           -------      -------      -------      -------       -------    -------
     Total gas customers                   405,142      394,181      385,322      376,895       368,646    360,392
                                           =======      =======      =======      =======       =======    =======

Operating Revenues (Millions of Dollars)
Residential                                $    17      $    16      $    15      $    16       $    15    $    16
House heating                                  265          249          236          238           202        203
Commercial and industrial                      145          133          126          128           110        113
Other                                            3           11            5           20            28         12
Unbilled                                        (1)          (4)           7           (3)            5         (1)
                                           -------      -------      -------      -------       -------    -------
     Subtotal                                  429          405          389          399           360        343
Other revenues (including
     transported for customers)                 22           24           22           17            23         23
                                           -------      -------      -------      -------       -------    -------
     Total gas revenues                        451          429          411          416           383        366
                                           -------      -------      -------      -------       -------    -------

Operating Expenses
Operating expenses,
     excluding depreciation                    333          302          302          326           279        261
Depreciation                                    28           27           26           26            24         23
                                           -------      -------      -------      -------       -------    -------
     Total operating expenses                  361          329          328          352           303        284
                                           -------      -------      -------      -------       -------    -------
Gas Operating Income                       $    90      $   100      $    83      $    64       $    80    $    82
                                           =======      =======      =======      =======       =======    =======
</TABLE>


Securities Statistics
Ratings on PECO Energy Company's securities
<TABLE>
<CAPTION>
                                              Mortgage Bonds                   Preferred Stock
                                                             Date                              Date
Agency                                   Rating       Established          Rating       Established
<S>                                     <C>            <C>                <C>             <C>
Duff and Phelps, Inc.                       BBB+          4/92             BBB-             8/91
Fitch Investors Service, Inc.               A-            9/92             BBB+             9/92
Moody's Investors Service                   Baa1          4/92             baa2             4/92
Standard & Poor's Corporation               BBB+          4/92             BBB              4/92
</TABLE>


NYSE-Composite Common Stock Prices, Earnings and Dividends by Quarter (Per
Share)
<TABLE>
<CAPTION>

                                    1997                                         1996
                Fourth        Third     Second     First     Fourth       Third       Second         First
               Quarter       Quarter    Quarter   Quarter    Quarter     Quarter      Quarter       Quarter
<S>            <C>
High price     $25-1/8      $24-5/16   $21-1/8    $26-3/8    $27-3/8     $26-1/4      $26-7/8        $32-1/2
Low price      $21-7/16     $20-3/4    $18-3/4    $20        $23-7/8     $23          $22-1/2        $26-1/4
Close          $24-1/4      $23-7/16   $21        $20-3/8    $25-1/4     $23-3/4      $26            $26-5/8
Earnings      ($8.51)        69(cent)   53(cent)   49(cent)   51(cent)    65(cent)     43(cent)       65(cent)
Dividends       45(cent)     45(cent)   45(cent)   45(cent)   45(cent)    43.5(cent)   43.5(cent)     43.5(cent)
</TABLE>
<PAGE>
48

Board of Directors

Susan W. Catherwood (54)
Chairman, Trustee Board,
The University of Pennsylvania Medical Center and Health System

Daniel L. Cooper (62)(2)
Former Vice President and General Manager,
Nuclear Services Division
Gilbert/Commonwealth, Inc.

M. Walter D'Alessio (64)
President and Chief Executive Officer,
Legg Mason Real Estate Services (Commercial mortgage banking
and pension fund advisors)

G. Fred DiBona, Jr. (46)
President and Chief Executive Officer,
Independence Blue Cross

R. Keith Elliott (55)
Chairman, President and Chief Executive Officer,
Hercules, Inc.

Richard G. Gilmore (70)(1)
Former Senior Vice President,
Finance and Chief Financial Officer of the Company

Richard H. Glanton, Esquire (51)(1)
Partner of the law firm Reed Smith Shaw and McClay

James A. Hagen (65)
Former Chairman, Conrail, Inc.

Admiral Kinnaird R. McKee (68)
Director Emeritus,
U.S. Navy Nuclear Propulsion

Joseph J. McLaughlin (69)(1)
Former President and Chief Executive Officer,
Beneficial Mutual Savings Bank

Corbin A. McNeill, Jr. (58)(1)
Chairman of the Board
President and Chief Executive Officer of the Company

John M. Palms, PhD. (62)
President,
University of South Carolina

Joseph F. Paquette, Jr. (63)(1)
Former Chairman of the Board of Directors of the Company

Ronald Rubin (66)(1)
Chief Executive Officer,
The Rubin Organization, Inc. (Real estate development and management)

Robert Subin (59)
Senior Vice President,
Campbell Soup Company

Officers

Corbin A. McNeill, Jr. (58)
Chairman of the Board of Directors
President and Chief Executive Officer

Dickinson M. Smith (64)
President, PECO Nuclear
and Chief Nuclear Officer

Gregory A. Cucchi (48)(3)
Senior Vice President
Ventures

James W. Durham (60)
Senior Vice President, Legal
and General Counsel

Michael J. Egan (43)(4)
Senior Vice President, Finance
and Chief Financial Officer

William J. Kaschub (55)
Senior Vice President,
Human Resources

Kenneth G. Lawrence (50)(4)
Senior Vice President,
Local Distribution Company

John M. Madara, Jr. (54)
Senior Vice President,
Power Generation Group

William H. Smith, III (49)(5)
Senior Vice President,
Business Services Group

Alvin J. Weigand (59)
Senior Vice President

Gerald R. Rainey (48)
Senior Vice President,
Nuclear Operations

Nancy J. Bessey (44)
Vice President,
Power Transactions

John B. Cotton (53)(6)
Vice President,
Station Support

John Doering, Jr. (54)
Vice President, Operations
Power Generation Group

Gregory P. Dudkin (40)(3)
Vice President,
Power Delivery

Drew B. Fetters (46)
Vice President,
Nuclear Planning and Development

Thomas P. Hill, Jr. (49)
Vice President and Controller

Cassandra A. Matthews (47)(7)
Vice President,
Information Systems

John P. McElwain (47)(6)
Vice President,
Nuclear Projects, PECO Nuclear

J. Barry Mitchell (50)
Vice President,
Finance and Treasurer

Thomas N. Mitchell (42)
Vice President,
Peach Bottom Atomic Power Station

William E. Powell, Jr. (61)
Vice President,
Support Services

James D. von Suskil (51)(8)
Vice President,
Limerick Generating Station

Katherine K. Combs (47)
Corporate Secretary

Edward J. Cullen, Jr. (50)
Assistant Corporate Secretary

Todd D. Cutler (37)
Assistant Corporate Secretary

Diana Moy Kelly (43)
Assistant Treasurer

George R. Shicora (51)
Assistant Treasurer

(1)  Member of the Executive Committee of the Board of Directors
(2)  Elected June 23, 1997
(3)  Effective June 1, 1997
(4)  Effective October 13, 1997
(5)  Effective November 7, 1997
(6)  Effective April 9, 1997
(7)  Effective July 28, 1997
(8)  Effective January 26, 1998