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

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

                                    FORM 10-K

[ X ]         ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
                         SECURITIES EXCHANGE ACT OF 1934
                   For the fiscal year ended December 31, 1995
                                       OR
[   ]       TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
                         SECURITIES EXCHANGE ACT OF 1934
    For the transition period from ___________________ to ___________________

                          Commission File Number 1-1401
                      ------------------------------------

                               PECO ENERGY COMPANY
             (Exact name of registrant as specified in its charter)

                Pennsylvania                               23-0970240
     (State or other jurisdiction of                    (I.R.S. Employer 
     incorporation or organization)                     Identification No.)

                P.O. Box 8699
    2301 Market Street, Philadelphia, PA                 (215) 841-4000
  (Address of principal executive offices)      (Registrant's telephone number, 
                                                      including area code) 
                                      19101
                                   (Zip Code)
                      ------------------------------------

           Securities registered pursuant to Section 12(b) of the Act:

     First and Refunding Mortgage Bonds (Registered on the New York
Stock Exchange):
<TABLE>
<S>                            <C>                          <C>                           <C>
6 1/8% Series due 1997 (*)        7 3/8% Series due 2000      6 1/2% Series due 2003       7 1/8% Series due 2023
5 3/8% Series due 1998            5 5/8% Series due 2001      6 3/8% Series due 2005       7 3/4% Series 2 due 2023
                                                                                           7 1/4% Series due 2024
__________________
(*) Also registered on the Philadelphia Stock Exchange
</TABLE>

     Cumulative Preferred Stock -- without par value (Registered on the New York
and Philadelphia Stock Exchanges):
$7.96 Series        $4.68 Series        $4.40 Series        $4.30 Series
                                                            $3.80 Series

     Common  Stock  --  without  par  value  (Registered  on the  New  York  and
Philadelphia Stock Exchanges)

     9.00% Cumulative Monthly Income Preferred Securities,  Series B, $25 stated
value, issued by PECO Energy Capital, L.P. and unconditionally guaranteed by the
Company (Registered on the New York Stock Exchange)

     Trust  Receipts of PECO Energy  Capital Trust I, each  representing a 8.72%
Cumulative Monthly Income Preferred Security, Series B, $25 stated value, issued
by PECO Energy  Capital,  L.P.  and  unconditionally  guaranteed  by the Company
(Registered on the New York Stock Exchange)

           Securities registered pursuant to Section 12(g) of the Act:
     Cumulative Preferred Stock -- without par value:
$7.48 Series                        $6.12 Series
                      ------------------------------------

     Indicate  by check mark  whether the  registrant  (1) has filed all reports
required to be filed by Section 13 or 15(d) of the  Securities  Exchange  Act of
1934  during the  preceding  12 months and (2) has been  subject to such  filing
requirements for the past 90 days.                Yes __X__      No____

     Indicate by check mark if disclosure of delinquent  filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best  of  the  registrant's   knowledge,  in  definitive  proxy  or  information
statements  incorporated  by  reference  in Part  III of this  Form  10-K or any
amendment to this Form 10-K. [ ]

     The aggregate  market value of the  registrant's  common stock (only voting
stock) held by  non-affiliates  of the registrant was  $6,832,147,699 at January
31, 1996.

     Indicate  the  number of  shares  outstanding  of each of the  registrant's
classes of common stock as of the latest practicable date.

     Common  Stock --  without  par value:  222,255,816  shares  outstanding  at
January 31, 1996.

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

                 DOCUMENTS INCORPORATED BY REFERENCE (In Part)

     Annual Report of PECO Energy Company to Shareholders for the year 1995
   is incorporated in part in Parts I, II and IV hereof, as specified herein.
         Proxy Statement of PECO Energy Company in connection with its
1996 Annual Meeting of Shareholders is incorporated in part in 
                     Part III hereof, as specified herein.
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<PAGE>

                                TABLE OF CONTENTS
                                                                        Page No.
PART I
     ITEM 1.   BUSINESS.......................................................1
               The Company....................................................1
               Electric Operations............................................1
                    General...................................................1
                    Limerick Generating Station...............................4
                    Peach Bottom Atomic Power Station.........................5
                    Salem Generating Station..................................6
               Fuel...........................................................8
                    Nuclear...................................................8
                    Coal.....................................................10
                    Oil......................................................11
                    Natural Gas..............................................11
               Gas Operations................................................11
               Segment Information...........................................12
               Rate Matters..................................................12
               Construction..................................................14
               Capital Requirements and Financing Activities.................15
               Employee Matters..............................................16
               Environmental Regulations.....................................17
                    Water....................................................17
                    Air......................................................17
                    Solid and Hazardous Waste................................18
                    Costs....................................................22
               Competition...................................................22
               Telecommunications............................................24
               PECO Energy Capital Corp. and Related Entities................24
               Executive Officers of the Registrant..........................25
     ITEM 2.   PROPERTIES....................................................27
     ITEM 3.   LEGAL PROCEEDINGS.............................................29
     ITEM 4.   SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS...........30

PART II
     ITEM 5.   MARKET FOR THE REGISTRANT'S COMMON EQUITY AND
                    RELATED STOCKHOLDER MATTERS..............................30
     ITEM 6.   SELECTED FINANCIAL DATA.......................................31
     ITEM 7.   MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
                    CONDITION AND RESULTS OF OPERATIONS......................31
     ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA...................31
     ITEM 9.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
                    ON ACCOUNTING AND FINANCIAL DISCLOSURE...................31

PART III
     ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT............31
     ITEM 11.  EXECUTIVE COMPENSATION........................................31
     ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
                    MANAGEMENT...............................................32
     ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS................32

PART IV
     ITEM 14.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON
                    FORM 8-K.................................................33
               Financial Statements and Financial Statement Schedule.........33
               REPORT OF INDEPENDENT ACCOUNTANTS.............................34
               SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS..............35
               Exhibits......................................................36
               Reports on Form 8-K...........................................39
     SIGNATURES

                                        i

<PAGE>
                                     PART I
ITEM 1.   BUSINESS

The Company

     PECO Energy Company (Company),  incorporated in Pennsylvania in 1929, is an
operating  utility  which  provides  electric  and gas  service to the public in
southeastern  Pennsylvania.  The total area served by the Company  covers  2,107
square miles. Electric service is supplied in an area of 1,972 square miles with
a  population  of  about   3,700,000,   including   1,600,000  in  the  City  of
Philadelphia.  Approximately  94% of the electric service area and 64% of retail
kilowatthour (kWh) sales are in the suburbs around  Philadelphia,  and 6% of the
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  1,900,000.  The Company has the
necessary franchise rights, which are generally non-exclusive, to operate in the
areas served.

     The Company is subject to regulation  by the  Pennsylvania  Public  Utility
Commission  (PUC) as to retail  electric and gas rates,  issuances of securities
and certain other aspects of the Company's  operations and by the Federal Energy
Regulatory  Commission (FERC) as to wholesale  electric and transmission  rates.
Specific  operations  of the Company  are also  subject to the  jurisdiction  of
various other federal, state, regional and local agencies,  including the United
States Nuclear  Regulatory  Commission  (NRC),  the United States  Environmental
Protection  Agency  (EPA),  the United States  Department  of Energy (DOE),  the
Delaware River Basin Commission and the Pennsylvania Department of Environmental
Protection  (PDEP).  The  Company's  Muddy Run Pumped  Storage  Project  and the
Conowingo Hydroelectric Project are subject to the licensing jurisdiction of the
FERC. Due to its ownership of subsidiary-company stock, the Company is a holding
company as defined by the Public Utility Holding Company Act of 1935 (1935 Act);
however,  it is predominantly  an operating  company and, by filing an exemption
statement  annually,  is exempt  from all  provisions  of the 1935  Act,  except
Section  9(a)(2)  relating to the  acquisition of securities of a public utility
company.


Electric Operations

General

     During 1995,  90.2% of the  Company's  operating  revenues and 93.5% of its
operating  income were from electric  operations.  Electric  sales and operating
revenues for 1995 by class of customer are set forth below:
<TABLE>
<CAPTION>
                                                        Operating
                                         Sales           Revenues
                                    (millions of kWh) (millions of $)
<S>                                      <C>             <C>   
Residential ...................          10,859          $1,401
Small commercial and industrial           6,299             739
Large commercial and industrial          15,976           1,147
Other .........................             860             137
                                         ------          ------
     Service territory ........          33,994           3,424
Interchange sales .............             496              17
Sales to other utilities ......          14,041             334
                                         ------          ------
     Total ....................          48,531          $3,775
                                         ======          ======
</TABLE>

     Energy from the Company's installed generating capacity together with power
purchases are utilized to satisfy the requirements of jurisdictional  customers,
to meet sales commitments to other utilities and to make spot sales.

                                        1

<PAGE>
     The net  installed  electric  generating  capacity  (summer  rating) of the
Company and its subsidiaries at December 31, 1995 was as follows:

<TABLE>
<CAPTION>
         Type of Capacity              Megawatts         % of Total
<S>                                      <C>                <C>  
     Nuclear .......................     4,040              44.5%
     Mine-mouth, coal-fired ........       709               7.8
     Service-area, coal-fired ......       725               8.0
     Oil-fired .....................     1,176              13.0
     Gas-fired .....................       201               2.2
     Hydro (includes pumped storage)     1,392              15.3
     Internal combustion ...........       835               9.2
                                         -----             -----

         Total .....................     9,078(1)(2)       100.0%
                                         =====             ===== 
<FN>
---------------
(1)  Includes capacity available for sale to other utilities.
(2)  See "Fuel" for sources of fuels used in electric generation.
</FN>
</TABLE>

     As a result of the developing  wholesale generation market, the Company has
increased both its wholesale  power  purchases and sales. In the ordinary course
of its business, the Company enters into long-term and short-term commitments to
buy and sell power.  At December 31, 1995, the Company had 1,199  megawatts (MW)
of installed  generating  capacity  available for sales to others.  In addition,
during 1995, the Company entered into an agreement to purchase energy associated
with 300 MW from 1996 through  2000 from an  unaffiliated  utility.  The Company
also has agreements  with other  utilities to sell energy and/or  capacity.  The
Company  has  long-term  agreements  over the next five years with  unaffiliated
utilities to sell energy associated with 1,185 MW of capacity. These power sales
agreements  extend  from  1996 to 2023.  See  note 4 of  Notes  to  Consolidated
Financial Statements included in the Company's Annual Report to Shareholders for
the year 1995.

     Annual and quarterly  operating  results can be  significantly  affected by
weather.  Traditionally,  sales of electricity are higher in the first and third
quarters due to colder  weather and warmer  weather,  respectively.  The maximum
hourly demand on the Company's  system was 7,244 MW which  occurred on August 4,
1995. The Company  estimates its  generating  reserve margin for 1996 to be 26%.
This is based on the most recent annual peak-load  forecast which assumes normal
peak weather conditions and the sale to other utilities of 400 MW of capacity.

     The   Company   is  a  member  of  the   Pennsylvania-New   Jersey-Maryland
Interconnection  Association  (PJM),  which  fully  integrates,  on the basis of
relative  cost  of  generation,   the  bulk-power  generating  and  transmission
operations  of eleven  investor-owned  electric  utilities  serving more than 22
million people in a  50,000-square-mile  territory.  In addition,  PJM companies
coordinate  planning and install  facilities to obtain the greatest  practicable
degree of reliability,  compatible economy and other advantages from the pooling
of  their  respective  electric  system  loads,   transmission   facilities  and
generating  capacity.  The maximum PJM demand of 48,524 MW occurred on August 2,
1995 when PJM's installed  capacity (summer rating) was 55,962 MW. The Company's
installed  capacity for 1996-99 is expected to be sufficient  for the Company to
meet its  obligation to supply its PJM reserve  margin share during that period.
During  1995,  the  Company  notified  the  FERC  of its  intention  to  propose
initiatives  to increase  wholesale  electric  competition  in the  Mid-Atlantic
region served by PJM. See "Competition."

     The  Company's  nuclear-generated   electricity  is  supplied  by  Limerick
Generating  Station  (Limerick)  Units No. 1 and No. 2 and Peach  Bottom  Atomic
Power  Station  (Peach  Bottom) Units No. 2 and No. 3, which are operated by the
Company,  and by Salem  Generating  Station (Salem) Units No. 1 and No. 2, which
are operated by Public  Service  Electric and Gas Company  (PSE&G).  The Company
owns 100% of  Limerick,  42.49% of Peach  Bottom and  42.59% of Salem.  Limerick
Units No. 1 and No. 2 each has a capacity of 1,115 MW;  Peach Bottom Units No. 2
and No. 3 each has a capacity  of 1,093 MW, of which the  Company is entitled to
464 MW of each  unit;  and Salem  Units No. 1 and No. 2 each has a  capacity  of
1,106 MW, of which the Company is entitled to 471 MW of each unit.

                                        2
<PAGE>
     The Company's nuclear generating facilities represent  approximately 45% of
its installed  generating  capacity and 65% of its investment in electric plant.
In 1995,  approximately 50% of the Company's  electric output was generated from
nuclear  sources.  Changes in  regulations by the NRC that require a substantial
increase in capital expenditures for the Company's nuclear generating facilities
or that result in increased  operating costs of nuclear  generating  units could
adversely affect the Company.

     The  Price-Anderson  Act sets the limit of liability of approximately  $8.9
billion  for claims that could arise from an  incident  involving  any  licensed
nuclear facility in the nation.  The limit is subject to increase to reflect the
effects  of  inflation  and  changes  in the number of  licensed  reactors.  All
utilities with nuclear  generating units,  including the Company,  have obtained
coverage for these potential claims through a combination of private  insurances
of $200 million and  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.  If the damages from an incident at a licensed  nuclear  facility
exceed $8.9 billion, the President of the United States is to submit to Congress
a plan for providing  additional  compensation to the injured parties.  Congress
could impose  further  revenue-raising  measures on the nuclear  industry to pay
claims. The Price-Anderson Act and the extensive regulation of nuclear safety by
the NRC do not preempt claims under state law for personal, property or punitive
damages related to radiation hazards.

     Although the NRC requires the maintenance of property  insurance on nuclear
power plants in the amount of $1.06 billion or the amount available from private
sources,  whichever is less, the Company maintains coverage in the amount of its
$2.75  billion  proportionate  share for each station.  The Company's  insurance
policies  provide  coverage for  decontamination  liability  expense,  premature
decommissioning  and loss or damage to its nuclear  facilities.  These  policies
require that insurance  proceeds  first be applied to assure that,  following an
accident,  the facility is in a safe and stable  condition and can be maintained
in such condition.  Within 30 days of stabilizing the reactor, the licensee must
submit  a report  to the NRC  which  provides  a  clean-up  plan  including  the
identification of all clean-up operations necessary to decontaminate the reactor
to  permit  either  the  resumption  of  operations  or  decommissioning  of the
facility. Under the Company's insurance policies,  proceeds not already expended
to place the reactor in a stable  condition  must be used to  decontaminate  the
facility. 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 NRC to maintain to provide funds for  decommissioning  the  facility.  These
proceeds would be paid to the fund to make up any difference  between the amount
of money in the fund at the time of the  early  decommissioning  and the  amount
that would have been in the fund if contributions  had been made over the normal
life of the  facility.  The  Company  is unable to  predict  what  effect  these
requirements may have on 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 $46  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.  Any such losses,
if not recovered through the ratemaking  process,  could have a material adverse
effect on the Company's financial condition or 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 policy contains a 21-week waiting period before
recovery of costs can  commence.  The premium for this coverage is subject to an
assessment  for adverse loss  experience.  The  Company's  maximum  share of any
assessment is $14 million per year.

     NRC  regulations  require that licensees of nuclear  generating  facilities
demonstrate  that funds will be available in certain  minimum amounts at the end
of the life of the facility to  decommission  the  facility.  The PUC,  based on
estimates of  decommissioning  costs for each of the nuclear facilities in which
the Company has an ownership  interest,  permits the Company to collect from its
customers  and deposit in  segregated  accounts  amounts  which,  together  with
earnings  thereon,  will be used to decommission  such nuclear  facilities.  The
Company's  ownership  portion of  decommissioning  costs is  approximately  $643
million  expressed  in  1990  dollars  to be  collected  over  the  life of each
generating unit.  Under current rates,  which reflect  decommissioning  costs of
$643 million, the

                                        3
<PAGE>
Company collects and expenses  approximately $20 million annually from customers
for  decommissioning  the Company's  ownership  portion of its nuclear units. At
December 31, 1995, the Company held $223 million in trust accounts, representing
amounts  recovered  from  customers and net realized and  unrealized  investment
earnings  thereon,  to fund  future  decommissioning  costs.  Based  on a recent
Company study, the Company's share of the cost to decommission its nuclear units
is  estimated to be $1.2 billion in 1995  dollars.  The Company will  ultimately
seek to recover through the ratemaking process increased  decommissioning costs,
although  such  recovery  is  not  assured.  In  February  1996,  the  Financial
Accounting  Standards Board (FASB) issued an Exposure Draft entitled "Accounting
for Certain  Liabilities  Related to Closure or Removal of  Long-Lived  Assets,"
which proposes, among other things, changes in the recognition,  measurement and
classification of  decommissioning  costs for nuclear generating  stations.  The
proposed  statement  would be effective for years  beginning  after December 15,
1996,  and  applies  to  all  entities   having  either  legal  or  constructive
obligations  (defined  as an  obligation  which the  entity  has  "little  or no
discretion to avoid") for closure or removal of long-lived  assets.  The FASB is
expected  to  issue a final  pronouncement  by the end of 1996.  For  additional
information  concerning  nuclear  decommissioning,   see  note  4  of  Notes  to
Consolidated  Financial  Statements  included in the Company's  Annual Report to
Shareholders for the year 1995.

Limerick Generating Station

     Limerick  Unit No. 1 achieved  a capacity  factor of 88% in 1995 and 85% in
1994.  Limerick Unit No. 2 achieved a capacity  factor of 85% in 1995 and 93% in
1994. Limerick Units No. 1 and No. 2 are each on a 24-month refueling cycle. The
last  refueling  outages  for  Units  No.  1 and No.  2 were in 1996  and  1995,
respectively.

     On May 24,  1995,  the NRC issued its  periodic  Systematic  Assessment  of
Licensee  Performance  (SALP)  Report for Limerick for the period  September 26,
1993 through April 1, 1995. Limerick achieved ratings of "1," the highest of the
three rating categories, in all four functional areas - Operations, Maintenance,
Engineering  and Plant  Support.  The NRC stated that,  overall,  it observed an
excellent  level of  performance  at Limerick.  The NRC noted  continued  strong
performance in the Operations and Engineering  areas during this SALP period and
improved  performance was noted in the Maintenance and Plant Support areas.  The
NRC stated  that  factors  contributing  to this level of  performance  included
excellent   management   oversight,   along  with  excellent   interdepartmental
communication  and coordination of activities.  Particularly,  the NRC noted the
Company's  excellent  planning and execution of the two refueling outages during
the SALP period and the aggressive  use of  probabilistic  safety  assessment in
scheduling  outage and non-outage  maintenance  activities.  The NRC also stated
that, in recognition of Limerick's  superior  performance,  the next SALP period
for Limerick has been  extended to 24 months and both the number of resident NRC
inspectors and planned total inspection hours have been reduced.

     In  October  1990,  General  Electric  Company  (GE)  reported  that  crack
indications were discovered near the seam welds of the core shroud assembly in a
GE Boiling Water Reactor (BWR) located  outside the United States.  As a result,
GE issued a letter requesting that the owners of GE BWRs take interim corrective
actions,  including a review of fabrication  records and visual  examinations of
accessible areas of the core shroud seam welds. Each of the reactors at Limerick
and Peach Bottom is a GE BWR.  Initial  examination  of Limerick  Unit No. 1 was
completed during the February 1996 refueling outage.  Although crack indications
were  identified  at  one  location,  the  Company  concluded  that  there  is a
substantial margin for each core shroud weld to allow for continued operation of
Unit No. 1 for a minimum of the next two operating cycles.  Initial  examination
of Unit No. 2 has been  scheduled for the refueling  outage  planned for January
1999 in accordance with industry experience and guidance.  Peach Bottom Unit No.
3 was  initially  examined  during  its  refueling  outage  in the fall of 1993.
Although  crack  indications  were  identified  at two  locations,  the  Company
presented its finding to the NRC and recommended continued operation of Unit No.
3 for a two-year  cycle.  Unit No. 3 was  re-examined  during its last refueling
outage in the fall of 1995 and the extent of cracking  identified was determined
to be  within  industry-established  guidelines.  In a letter  to the NRC  dated
November 3, 1995, the Company  concluded that there is a substantial  margin for
each core shroud weld to allow for  continued  operation of Unit No. 3 until its
next refueling outage, scheduled for 1997, at which time it will be reinspected.
Peach Bottom Unit No. 2 was

                                        4
<PAGE>
examined in October  1994 during its last  refueling  outage and the  inspection
revealed a minimal  number of flaws.  In a letter  dated  November 7, 1994,  the
Company  submitted  its  findings  to the NRC  and  also  recommended  continued
operation of Unit No. 2 until its next refueling outage, scheduled for September
1996, at which time it will be reinspected. The Company is also participating in
a GE BWR Owners Group to develop long-term corrective actions.

     The NRC has raised  concerns that the Thermo-Lag  330 fire barrier  systems
used to protect cables and equipment may not provide the necessary level of fire
protection  and requested  licensees to describe  short- and long-term  measures
being taken to address  this  concern.  The Company has informed the NRC that it
has taken  short-term  corrective  actions to address  the  inadequacies  of the
Thermo-Lag  barriers installed at Limerick and Peach Bottom and is participating
in an industry-coordinated program to provide long-term corrective solutions. By
letter  dated  December  21,  1992,  the NRC stated that the  Company's  interim
actions were acceptable.  The Company has been in contact with the NRC regarding
the Company's  long-term  measures to address Thermo-Lag fire barrier issues. In
1995, the Company  completed its  engineering  re-analysis for both Peach Bottom
and Limerick. This re-analysis identified proposed modifications to be performed
over the next several  years at both plants in order to implement  the long-term
measures addressing the concern over Thermo-Lag use.

     In 1992,  the Company  requested  authorization  from the NRC to rerate the
maximum  reactor-core  power levels of each Limerick unit by 5% to 1,115 MW. The
NRC approved the  Company's  request for Unit No. 2 on February 16, 1995 and for
Unit No. 1 on  January  24,  1996.  Modifications  to Unit No. 2 were  completed
during  the  Unit's  1995  refueling  outage.  Modifications  to Unit No. 1 were
completed during the Unit's February 1996 refueling outage.

     Water for the  operation  of  Limerick is drawn from the  Schuylkill  River
adjacent to Limerick and from the Perkiomen Creek, a tributary of the Schuylkill
River.  During  certain  periods of the year,  generally  the summer  months but
possibly for as much as six months or more in some years,  the Company would not
be able to operate Limerick without the use of supplemental cooling water due to
existing  regulatory water withdrawal  constraints  applicable to the Schuylkill
River and the  Perkiomen  Creek.  Supplemental  cooling  water for  Limerick  is
provided  by a  supplemental  cooling  water  system  which draws water from the
Delaware  River at the Point  Pleasant  Pumping  Station,  transports  it to the
Bradshaw Reservoir (Point Pleasant Project),  then to the east and main branches
of the Perkiomen Creek and finally to Limerick.  The supplemental  cooling water
system  also  provides  water for  public  use to two  Montgomery  County  water
authorities.  The Company has  obtained  all  permits for the  construction  and
operation  of the  supplemental  cooling  water  system.  Certain of the permits
relating to the operation of the system must be renewed periodically.

     The Company has also  entered  into an  agreement  with a  municipality  to
secure a backup source of water for the operation of Limerick  should the amount
of water from the  supplemental  cooling water system not be sufficient.  Should
the  supplemental  cooling water system be completely  unavailable,  this backup
source is  capable of  providing  only  enough  cooling  water to  operate  both
Limerick  units  simultaneously  at 70% of rated  capacity for short  periods of
time.

Peach Bottom Atomic Power Station

     Peach  Bottom Unit No. 2 achieved a capacity  factor of 98% in 1995 and 81%
in 1994.  Peach Bottom Unit No. 3 achieved a capacity  factor of 78% in 1995 and
98% in 1994. Peach Bottom Units No. 2 and No. 3 are each on a 24-month refueling
cycle.  The last  refueling  outages  for Units No. 2 and No. 3 were in 1994 and
1995, respectively.

     On  December  5, 1995,  the NRC issued its  periodic  SALP Report for Peach
Bottom for the period May 1, 1994 to October 15,  1995.  Peach  Bottom  achieved
ratings of "1" in the areas of Operations,  Maintenance  and Plant Support.  The
area of  Engineering  achieved  a  rating  of  "2."  Overall,  the NRC  observed
excellent  performance  at Peach Bottom during the  assessment  period.  Station
management oversight,  effective use of performance enhancement at all levels of
the organization and other measures in identifying and evaluating issues

                                        5
<PAGE>
contributed to the strong performance. The NRC noted performance improvements in
all of the assessment  areas,  particularly  in  Maintenance  and Plant Support.
Although the NRC noted that  excellent  performance  was often  displayed in the
Engineering area, errors in modification work, in addition to some other lapses,
indicated inconsistent engineering performance. The Company is taking actions to
further improve Peach Bottom performance.

     By letter dated October 18, 1994, the NRC approved the Company's request to
rerate the  authorized  maximum  reactor-core  power levels of each Peach Bottom
unit by 5% to 1,093  MW.  The  amendment  of the Unit No. 2  facility  operating
license  was  effective  upon  the  date of the  NRC  approval  letter,  and the
associated  hardware  changes were  implemented  during the Unit No. 2 refueling
outage in the fall of 1994.  The  amendment for Unit No. 3 was issued by the NRC
on July 18, 1995 and the associated hardware changes were implemented during the
Unit No. 3 refueling outage in the fall of 1995.

     In  addition to the  matters  discussed  above,  see  "Limerick  Generating
Station" for a discussion of certain  matters which affect both Peach Bottom and
Limerick.

Salem Generating Station

     Salem Unit No. 1 achieved a capacity factor of 26% in 1995 and 59% in 1994.
Salem  Unit No. 2  achieved  a  capacity  factor of 21% in 1995 and 58% in 1994.
Salem Units No. 1 and No. 2 are each on an 18-month  refueling  cycle.  The last
refueling outages for Units No. 1 and No. 2 were in 1995.

     Salem Units No. 1 and No. 2 have been out of service since May 16, 1995 and
June 7, 1995,  respectively,  due to various operational and technical problems.
The Company has been  informed by PSE&G that since the shutdown of Salem,  PSE&G
has been engaged in an assessment of each unit to identify and complete the work
necessary to achieve  restart.  PSE&G has stated that it will keep each unit off
line until it is  satisfied  that the unit is ready to return to service  and to
operate  reliably  over the long  term and the NRC has  agreed  that the unit is
sufficiently prepared to restart. On June 9, 1995, the NRC issued a Confirmatory
Action Letter documenting these commitments of PSE&G.

     On December 11, 1995,  PSE&G  presented  its restart plan for both units to
the NRC at a public meeting. On February 13, 1996, the NRC staff issued a letter
to PSE&G  indicating that it had concluded that PSE&G's overall restart plan, if
implemented effectively,  should adequately address the numerous Salem issues to
support a plant restart,  and describing  further actions the NRC will undertake
to confirm  that  PSE&G's  actions have  resulted in the  necessary  performance
improvements to support plant restart.

     The Company has been informed by PSE&G that as a part of PSE&G's review, an
examination  is being  performed on the steam  generators,  which are large heat
exchangers  used to produce  steam to drive the  turbines.  Within the industry,
certain  pressurized  water  reactors  (PWRs) other than Salem have  experienced
cracking in a sufficient  number of the steam generator tubes to require various
modifications  to these tubes and  replacement  of the steam  generators in some
cases.  Until the current  outage,  regular  periodic  inspections  of the steam
generators  for each Salem unit have  resulted  in repairs of a small  number of
tubes well within NRC limits.  As a result of the experience of other  utilities
with cracking in steam generator  tubes, in April 1995, the NRC issued a generic
letter to all utilities with PWRs. This generic letter requested  utilities with
PWRs to conduct steam  generator  examinations  with more  sensitive  inspection
devices  capable of  detecting  evidence  of  degradation.  Subsequently,  PSE&G
conducted  steam  generator  inspections  of the Salem  units  using the  latest
technology  available,  including a new, more  sensitive,  eddy current  testing
device.

     With respect to Salem Unit No. 1, the most recent  inspection  of the steam
generators is not complete,  but partial  results from eddy current  inspections
conducted in February  1996  indicate  degradation  in a  significant  number of
tubes.  The  inspections  are continuing and PSE&G has decided to remove several
tubes for  laboratory  examination  to confirm the  results of the  inspections.
Removal of the tubes is expected to commence in April and preliminary results of
the state of Salem Unit No. 1 tubes from the subsequent laboratory examinations

                                        6
<PAGE>
should be known in the third quarter of 1996.  However,  based on the results of
inspections to date, PSE&G has concluded that the Salem Unit No. 1 outage, which
was expected to be completed in the second quarter of 1996,  will be required to
be extended  for a  substantial  additional  period to evaluate the state of the
steam generators and to subsequently  determine an appropriate course of action.
Degradation of steam generators in PWRs has become of increasing concern for the
nuclear  industry.  Nationally and  internationally,  utilities have  undertaken
actions to repair or replace steam  generators.  In the extreme,  degradation of
steam  generators has contributed to the retirement of several  American nuclear
power reactors.  After the Salem Unit No. 1 tubes are fully examined, PSE&G will
be able to  evaluate  its  course of  action in light of NRC and other  industry
requirements.

     The examination of the Salem Unit No. 2 generators was completed in January
1996 using the same  inspection  procedure used in the examination of Salem Unit
No. 1. The results of the Salem Unit No. 2 inspection  are being  reviewed again
to  confirm  their  results  in light of the  experience  with Salem Unit No. 1.
Although  this  review has not yet been  completed,  results  to date  appear to
confirm  that the  condition of the Salem Unit No. 2 steam  generators  are well
within  current  operating  limits at the present  time.  PSE&G has also removed
tubes from Salem Unit No. 2 steam generators for laboratory  analysis to confirm
the results of this testing, the results of which should be known in May.

     PSE&G had  planned  to return  Salem  Unit No. 1 to  service  in the second
quarter of 1996 and Salem Unit No. 2 in the third  quarter of 1996.  As a result
of the extent of the  recently  discovered  degradation  in the Salem Unit No. 1
steam generators, PSE&G is focusing its efforts on returning Salem Unit No. 2 to
service in the third quarter of 1996. The additional steam generator inspections
and testing on Salem Unit No. 2 are not expected to adversely  affect the timing
of its  restart.  However,  because  the  timing of the  restart  is  subject to
satisfactory  completion of the  requirements of the restart plan, as determined
by PSE&G and the NRC, no assurance can be given that the  projected  return date
will be met. For information  concerning  additional  costs  associated with the
shutdown of Salem,  see  "Management's  Discussion  and  Analysis  of  Financial
Condition  and  Results  of  Operations"  and note 24 of  Notes to  Consolidated
Financial Statements in the Company's Annual Report to Shareholders for the year
1995 and "Rate Matters."

     The  Company has been  informed  by PSE&G that on January 3, 1995,  the NRC
issued  its  periodic  SALP  Report for Salem for the  period  June 20,  1993 to
November 5, 1994.  Salem received  ratings of "3" in the areas of Operations and
Maintenance, a rating of "2" in the area of Engineering,  and a rating of "1" in
the area of Plant Support.  The NRC noted an overall  decline in performance and
evidenced  particular  concern  with  plant and  operator  challenges  caused by
repetitive  equipment  problems and  personnel  errors.  The NRC also noted that
although PSE&G has initiated several  comprehensive actions within the past year
to improve plant  performance,  and that some recent incremental gains have been
made, these efforts have yet to noticeably change overall performance at Salem.

     The Company has been  informed by PSE&G that  PSE&G's own  assessments,  as
well as those by the NRC and the Institute of Nuclear Power Operations, indicate
that additional  efforts are required to further improve operating  performance,
and that PSE&G is committed to taking the necessary  actions to address  Salem's
performance needs. It is anticipated that the NRC will maintain a close watch on
Salem's  performance and corrective  actions  related to the Salem shutdown.  No
assurance can be given as to what, if any, further or additional  actions may be
taken or required by the NRC to improve Salem's performance.

     In addition to the matters  discussed  above,  see "Legal  Proceedings" and
"Environmental Regulations -- Water."

                                        7
<PAGE>



Fuel

     The following table shows the Company's sources of electric output for 1995
and as estimated for 1996:

<TABLE>
<CAPTION>
                                                            1995    1996 (Est.) (1)
<S>                                                         <C>        <C>  
     Nuclear .......................................        50.0%      54.5%
     Mine-mouth, coal-fired ........................         9.5        9.6
     Service-area, coal-fired ......................         6.2        8.5
     Oil-fired .....................................         1.8        3.2
     Gas-fired .....................................         3.6        4.2
     Hydro (includes pumped storage) ...............         1.3        2.6
     Internal combustion ...........................         0.3        0.1
     Purchased, interchange and nonutility generated        27.3       17.3
                                                            ----       ----
                                                           100.0%     100.0%
                                                           =====      ===== 
<FN>
---------------
(1)  Does not reflect the extended  outage  beyond June 1996 of Salem Unit No. 1
     due to cracking in steam generator tubes.
</FN>
</TABLE>

     The following table shows the Company's  average fuel cost used to generate
electricity:
<TABLE>
<CAPTION>
                                         1991       1992       1993        1994      1995
<S>                                   <C>        <C>        <C>        <C>        <C>      
     Nuclear
          Cost per million Btu(1)     $    0.64  $    0.53  $    0.56  $    0.53  $    0.47
     Coal
          Mine-mouth plants
            Cost per ton ........         37.26      33.75      32.73      33.30      32.68
            Cost per million Btu           1.51       1.36       1.32       1.34       1.32
          Service-area plants
            Cost per ton ........         50.24      45.25      43.38      38.76      38.82
            Cost per million Btu           2.00       1.78       1.66       1.51       1.51
     Oil
          Residual
            Cost per barrel .....         19.42      15.94      15.87      16.22      14.92
            Cost per million Btu           3.11       2.53       2.50       2.54       2.40
          Distillate
            Cost per barrel .....         29.90      24.96      27.21      22.77      20.74
            Cost per million Btu           5.12       4.26       4.15       3.87       3.66
     Gas
            Cost per mcf ........          --         3.05       2.86       2.31       2.13
            Cost per million Btu           --         2.96       2.77       2.25       2.00
<FN>
------
(1) British thermal unit.
</FN>
</TABLE>

Nuclear

     The cycle of production and utilization of nuclear fuel includes the mining
and milling of uranium ore; the  conversion of uranium  concentrates  to uranium
hexafluoride;  the enrichment of the uranium  hexafluoride;  the  fabrication of
fuel  assemblies;  and the  utilization  of the nuclear  fuel in the  generating
station   reactor.   The  Company  has  contracts  for  the  supply  of  uranium
concentrates  for  Limerick  and Peach Bottom  which  extend  through  2002.  On
February 23,  1995,  two  companies  which supply  uranium  concentrates  to the
Company  filed  petitions  for  bankruptcy  protection  under  Chapter 11 of the
Bankruptcy  Code.  The Company has  contracts  with the two  companies to supply
approximately  half of the  Company's  1995 and 1996  requirements  for  uranium
concentrates.  In addition,  one of the  companies  is under  contract to supply
approximately  25% of the Company's  uranium  concentrate  requirements  for the
period 1997 to 2002. The Company has made alternative arrangements

                                        8
<PAGE>
with  other  suppliers  to  satisfy  its  short-term  requirements  for  uranium
concentrates.  The Company is also finalizing arrangements with another supplier
to satisfy the Company's  longer-term needs. The Company does not anticipate any
difficulty in obtaining its requirements for uranium concentrates. The Company's
contracts for uranium concentrates are allocated to Limerick and Peach Bottom on
an as-needed  basis.  PSE&G has informed the Company that it presently has under
contract  sufficient  uranium  concentrates to fully meet the current  projected
requirements  for Salem through 2000 and 60% of the  requirements  through 2002.
PSE&G has informed the Company that it does not  anticipate  any  difficulty  in
obtaining  its  requirements  for  uranium  concentrates.  The  following  table
summarizes the years through which the Company and PSE&G have contracted for the
other segments of the nuclear fuel supply cycle:

<TABLE>
<CAPTION>
                                Conversion    Enrichment   Fabrication
<S>                                 <C>          <C>        <C> 
     Limerick Unit No. 1 ...        (1)           (2)          2003
     Limerick Unit No. 2 ...        (1)           (2)          2004
     Peach Bottom Unit No. 2        (1)           (2)          1999
     Peach Bottom Unit No. 3        (1)           (2)          1998
     Salem Unit No. 1 ......        2000          (3)          2004
     Salem Unit No. 2 ......        2000          (3)          2005
<FN>
---------------
(1)  The  Company  has  commitments  for  100% of its  conversion  services  for
     Limerick and Peach Bottom through 1997. Approximately 40% of the conversion
     services  requirements  are covered  through  2001.  The  Company  does not
     anticipate any difficulty in obtaining  necessary  conversion  services for
     Limerick and Peach Bottom.

(2)  The  Company  has  contractual  commitments  for  enrichment  services  for
     Limerick and Peach Bottom with the United  States  Enrichment  Corporation.
     These  commitments  represent 100% of the enrichment  requirements  through
     1998 and 70% through 1999.  The Company does not  anticipate any difficulty
     in obtaining necessary enrichment services for Limerick and Peach Bottom.

(3)  PSE&G  has  contractual  commitments  for 100% of  enrichment  requirements
     through 1998; approximately 50% through 2002; and approximately 30% through
     2004. The Company has been informed by PSE&G that PSE&G does not anticipate
     any difficulty in obtaining necessary enrichment services for Salem.
</FN>
</TABLE>

     There are no commercial  facilities for the  reprocessing  of spent nuclear
fuel currently in operation in the United  States,  nor has the NRC licensed any
such  facilities.  The Company  currently stores all spent nuclear fuel from its
nuclear  generating  facilities in on-site,  spent-fuel storage pools. By letter
dated November 29, 1994,  the NRC approved the Company's  request to install new
high-density,  spent-fuel  storage  racks at  Limerick,  which will  provide for
storage capacity to 2007. The new configuration  will be designed to accommodate
rod consolidation.  Spent-fuel racks at Peach Bottom have storage capacity until
2000 for Unit No. 2 and 2001 for Unit No. 3.  Options for  expansion  of storage
capacity at Peach Bottom,  including rod consolidation,  are being investigated.
The Company has been  informed  by PSE&G that as a result of  reracking  the two
spent-fuel pools at Salem, the spent-fuel  storage capability of Salem Units No.
1 and No. 2 is estimated to be 2008 and 2012, respectively.

     Under the Nuclear  Waste  Policy Act of 1982  (NWPA),  the DOE was to begin
accepting spent fuel for permanent  off-site storage no later than 1998. The DOE
has stated  that it has no legal  obligation  under the NWPA to begin  accepting
spent fuel absent an operational  repository or other facility constructed under
the  NWPA.  The  DOE  acknowledges,  however,  that  it  may  have  created  the
expectation  of such a commitment  on the part of  utilities by issuing  certain
regulations and projected waste acceptance schedules.  In June 1994, a number of
utilities and state agencies, including the PUC, filed a lawsuit against the DOE
seeking a  determination  of the DOE's legal  obligation to accept fuel by 1998.
The DOE has  stated  that it will  not be able to open a  permanent,  high-level
nuclear waste  repository  until 2015, at the earliest.  The DOE stated that the
delay was a result of federal  budget  cuts,  the DOE seeking new data about the
suitability  of  the  proposed  repository  site  at  Yucca  Mountain,   Nevada,
opposition to this  location for the  repository  and the DOE's  revision of its
civilian nuclear waste program.  Legislation has been introduced in Congress for
the construction of a temporary storage

                                        9
<PAGE>
facility which would accept spent nuclear fuel from utilities  beginning in 1998
or soon  thereafter.  Although  progress  is being  made at Yucca  Mountain  and
several  communities  have expressed  interest in providing a temporary  storage
site, the Company cannot predict when the temporary  federal storage  facilities
or permanent  repository will become available.  The DOE is exploring options to
address  delays in the  currently  projected  waste  acceptance  schedules.  The
options  under  consideration  by the DOE  include  offsetting  a portion of the
financial burden associated with the costs of continued on-site storage of spent
fuel after 1998.  Under the NWPA, the DOE is authorized to assess  utilities for
the cost of nuclear fuel disposal.  The current cost of such disposal is one mil
($.001) per kWh of net nuclear  generation.  The 1995  charge  collected  by the
Company from its customers for spent-fuel disposal was $21 million.  The DOE may
revise this charge as necessary for full-cost recovery of nuclear fuel disposal.

     As a by-product of their operations,  nuclear  generating units,  including
those in which the Company owns an interest, produce Low Level Radioactive Waste
(LLRW).  LLRW is accumulated at each facility and  permanently  disposed of at a
federally  licensed disposal  facility.  The Company is currently  shipping LLRW
generated at Peach  Bottom and  Limerick to the site located in Barnwell,  South
Carolina for disposal.  Due to the uncertainty of the continued  availability of
LLRW disposal sites, on-site storage facilities were constructed at Peach Bottom
and Limerick, each with five-year storage capacities.

     The  Company is also  pursuing  alternative  disposal  strategies  for LLRW
generated at Peach Bottom and Limerick,  including an aggressive  LLRW reduction
program.   Pennsylvania  is  the  host  site  for  LLRW  generators  located  in
Pennsylvania,  Delaware,  Maryland and West Virginia and is pursuing a permanent
disposal site through a volunteer  siting  process.  The Company has contributed
$12 million towards the total cost of a permanent Pennsylvania disposal site.

     The Company has been  informed by PSE&G that it has an on-site LLRW storage
facility at Salem, with a five-year storage capacity. PSE&G ships LLRW generated
at Salem to Barnwell,  South  Carolina and currently uses the Salem facility for
interim  storage.  PSE&G has also advised the Company that New Jersey also plans
to host a LLRW  disposal  site.  The  Company,  as a Salem  co-owner,  has  paid
$857,000 as its share of the New Jersey siting costs.

     The National  Energy Policy Act of 1992 (Energy Act) requires,  among other
things,  that utilities with nuclear  reactors pay for the  decommissioning  and
decontamination of the DOE nuclear fuel enrichment  facilities.  The total costs
to domestic utilities are estimated to be $150 million per year for 15 years, of
which the Company's  share is $5 million per year.  The Energy Act provides that
these costs are to be  recoverable  in the same manner as other fuel costs.  The
Company has recorded the liability and a related regulatory asset of $54 million
for such costs at December 31, 1995. The Company is currently  recovering  these
costs through the Energy Cost Adjustment (ECA).

     The  Company  is  currently  recovering  in rates  the  costs  for  nuclear
decommissioning  and   decontamination   (based  on  1990  cost  estimates)  and
spent-fuel   storage.   The  Company   believes  that  the  ultimate   costs  of
decommissioning  and  decontamination,  spent-fuel  disposal and any  assessment
under the Energy Act will continue to be  recoverable  through  rates,  although
such   recovery  is  not  assured.   For   additional   information   concerning
decommissioning, see "Electric Operations - General."

Coal

     The Company has a 20.99% ownership  interest in Keystone Station (Keystone)
and a 20.72% ownership  interest in Conemaugh Station  (Conemaugh),  coal-fired,
mine-mouth  generating stations in western Pennsylvania operated by Pennsylvania
Electric Company.  A majority of Keystone's fuel requirements is supplied by one
coal company under a contract  which expires on December 31, 2004.  The contract
calls for varying  amounts of coal purchases as follows:  between  3,000,000 and
3,500,000 tons for each of the years 1996 through 1999; and a total of 6,500,000
tons for the years 2000 through 2004. At December 31, 1995, approximately 20% of
Conemaugh's fuel  requirements  were secured by a long-term  contract and 21% by
several short-term contracts.

                                       10
<PAGE>
     The  Company has  entered  into  medium-term  contracts  for a  significant
portion of its coal  requirements  and makes spot  purchases  for the balance of
coal required by its  Philadelphia-area,  coal-fired units at Eddystone  Station
(Eddystone)  and Cromby  Station  (Cromby).  At January 1, 1996, the Company had
contracts with two suppliers for 1.5 million tons per year or approximately  80%
of expected annual requirements. Both contracts expire on December 31, 2000.

     The coal requirements of each station not covered by existing contracts are
met through additional short-term contracts or spot purchases from suppliers.

Oil

     The Company customarily enters into yearly purchase orders with its various
oil suppliers for the bulk of its  requirements and makes spot purchases for the
balance.  At present,  the Company's  purchase orders are sufficient to meet the
estimated residual fuel oil needs of its oil-fired generating units through June
1996,  when current orders expire and new yearly orders begin.  Purchase  orders
for  distillate  fuel oil are expected to meet the Company's  needs through June
1996, when current orders expire and new yearly orders begin.

Natural Gas

     The  Company  obtains  natural  gas  for  electric   generation  through  a
combination of short-term  orders and spot purchases made on the open market, as
well as through the Company's own City Gate Sales  Tariff.  The Company  obtains
the  limited  quantities  of  natural  gas  used by the  auxiliary  boilers  and
pollution control equipment at Eddystone through the same means. The Company has
the  capability  to use  either  oil or  natural  gas at  Cromby  Unit No. 2 and
Eddystone Units No. 3 and No. 4.

Gas Operations

     During  1995,  9.8% of the  Company's  operating  revenues  and 6.5% of its
operating income were from gas operations.  Gas sales and operating revenues for
1995 by class of customer are set forth below:

<TABLE>
<CAPTION>
                                                                  Operating
                                                     Sales         Revenues
                                                     (mmcf)     (millions of $)
<S>                                                  <C>           <C>    
     House heating .........................         31,848        $   240
     Residential (other than house heating)           1,516             15
     Commercial and industrial .............         19,422            129
     Other .................................          1,184              4
                                                    -------        -------
         Total gas sales ...................         53,970            388
     Gas transported for customers .........         48,531             22
                                                    -------        -------
         Total gas sales and gas transported        102,501        $   410
                                                    =======        =======
</TABLE>

     Annual and quarterly  operating  results can be  significantly  affected by
weather. Traditionally, sales of gas are higher in the first and fourth quarters
due to colder weather.

     The Company's  natural gas supply is provided by purchases from a number of
suppliers for terms of up to five years.  These  purchases  are delivered  under
several long-term firm transportation  contracts with Texas Eastern Transmission
Corporation  (Texas  Eastern)  and  Transcontinental  Gas Pipe Line  Corporation
(Transcontinental).  The Company's aggregate annual entitlement under these firm
transportation contracts is 98.1 million dekatherms. Peak gas is provided by the
Company's liquefied natural gas facility and propane-air plant (see "ITEM 2.
PROPERTIES").

                                       11
<PAGE>
     Through service agreements with Texas Eastern, Transcontinental, Equitrans,
Inc. and CNG  Transmission  Corporation,  underground  storage  capacity of 21.5
million  dekatherms  is  under  contract  to  the  Company.   Natural  gas  from
underground  storage  represents  approximately  40%  of the  Company's  1995-96
heating season supplies.

     As a result  of FERC  Order  636 and the  subsequent  restructuring  of the
interstate  pipeline industry,  the gas distribution  merchant function has come
under continued pressure as smaller customers elect to purchase non- utility gas
supplies.  This has raised  significant  issues at the state level regarding the
long-term  role of the gas  distribution  utility as a  merchant.  Other  policy
issues have arisen regarding the obligation to serve by the utility, the erosion
of tax  base,  the  potential  for  stranded  costs  associated  with  long-term
contracts,  the  implications for social programs now supported by utilities and
overall system reliability.

     PECO Gas Supply Company,  a wholly owned subsidiary,  was formed in 1995 as
an unregulated  marketing  enterprise.  PECO Gas Supply Company is a member of a
natural gas buying  cooperative,  also formed in 1995, to enhance reliability of
service  and  access  less  expensive  gas  supplies  for its eight gas  utility
members.

     Eastern Pennsylvania  Exploration Company, a wholly owned subsidiary,  is a
party to several joint ventures  formed to develop  natural gas resources in the
Gulf Coast area. These joint ventures do not contribute to the Company's natural
gas supply. The Company is engaged in pursuing the sale of these joint ventures.


Segment Information

     Segment  information is incorporated herein by reference to note 2 of Notes
to Consolidated  Financial Statements included in the Company's Annual Report to
Shareholders for the year 1995.


Rate Matters

     In 1995, approximately 90% of the Company's electric sales revenue and 100%
of its gas sales  revenue were derived  pursuant to rates  regulated by the PUC.
The PUC  establishes  through  regulatory  proceedings  the base rates which the
Company may charge for  electric and gas service in  Pennsylvania.  In addition,
the  PUC  regulates  various  fuel  and tax  adjustment  clauses  applicable  to
customers' bills. The Company's  wholesale  electric and transmission  rates are
regulated  by  the  FERC.  For   information   concerning   wholesale   electric
competition, see "Competition."

     The  Company  has agreed  with the PUC not to seek an  increase in electric
base rates before April 1, 1999 except under specified  circumstances  for items
such as energy  cost  adjustments,  changes in state  taxes,  changes in federal
taxes,  demand  side  management  surcharges,  and  increases  in nuclear  plant
decommissioning expenses or funding requirements and spent nuclear fuel disposal
expenses.

     The Company's last electric base rate case,  intended  primarily to recover
costs associated with Limerick Unit No. 2 and associated common facilities,  was
filed in 1989.  The Company  voluntarily  excluded 400 MW of capacity  from base
rates,  and the PUC denied a return on common equity on an additional  399 MW of
capacity.  Under its  electric  tariffs,  the  Company  is allowed to retain for
shareholders any proceeds above the average energy cost for sales of this 399 MW
of capacity and/or  associated  energy.  In addition,  beginning April 1994, the
Company became entitled to share in the benefits which result from the operation
of both  Limerick  Units No. 1 and No. 2 through the  retention  of 16.5% of the
energy  savings,  subject to certain  limits.  During 1995,  1994 and 1993,  the
Company  recorded  as  revenue  net of fuel  costs  $79,  $68  and $38  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.

     On February  22,  1996,  the PUC  approved  the  Company's  petition  for a
declaratory  accounting  order to  change  the  estimated  depreciable  lives of
certain of the Company's electric plant. The order approves the reduction of the
terminal dates by ten years, for depreciation accrual purposes only, of Limerick
Units No. 1 and

                                       12
<PAGE>
No. 2 and associated  common  facilities,  the utilization of new life spans for
various  categories  of electric  production  plant and changes in the remaining
life estimates for  transmission,  distribution,  general and common plant.  The
order also approves the amortization  over a nine-year period of $331 million of
deferred  Limerick  costs  representing  $240  million of  carrying  charges and
depreciation  associated with 50% of Limerick common  facilities and $91 million
of operating and maintenance expenses, depreciation and accrued carrying charges
on the Company's  capital  investment in Limerick Unit No. 2 and 50% of Limerick
common  facilities  during the period  from  January  8,  1990,  the  commercial
operation  date of Limerick Unit No. 2, until April 20, 1990, the effective date
of the Limerick Unit No. 2 rate order.  The changes will  increase  depreciation
and  amortization  on assets  associated  with  Limerick by  approximately  $100
million per year and decrease  depreciation  and  amortization  on other Company
assets by approximately $10 million per year, for a net increase in depreciation
and  amortization  of  approximately  $90 million  per year.  The order will not
increase  rates charged to customers.  The changes will be effective  October 1,
1996.

     Effective  January  1995,  in  accordance  with a PUC Joint  Petition,  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
Statement  of  Financial   Accounting  Standards  (SFAS)  No.  106,  "Employers'
Accounting for Postretirement Benefits Other Than Pensions." See note 7 of Notes
to Consolidated  Financial Statements included in the Company's Annual Report to
Shareholders for the year 1995.  Subsequent to January 1, 1995,  retail electric
non-pension  postretirement  benefits expense in excess of the amount allowed to
be  recovered  under the Joint  Petition  may not be  deferred  for future  rate
recovery. In accordance with the Joint Petition, any of the parties to the Joint
Petition may elect to void the  settlement in the event current rate recovery of
non-pension postretirement benefits expense is ultimately disallowed as a result
of the Office of Consumer Advocate's appeal to the Supreme Court of Pennsylvania
of cases  involving other  Pennsylvania  utilities.  In such event,  the Company
would  refund to  customers,  with  interest,  any  increased  base rate amounts
collected.

     The  Company  recovers  fuel and gas costs  through  base rates and various
automatic  adjustment clauses.  The Company's ECA, applicable to retail electric
service,  is adjusted annually.  Pursuant to a PUC proceeding  applicable to all
Pennsylvania  gas utilities,  effective March 1, 1996,  purchased gas cost rates
are  adjusted  quarterly  in lieu of annual  filings.  Regulatory  audits of the
operation of the adjustment  clauses are conducted to determine if refunds to or
recoupments   from   customers   are   necessary   as  a  result   of  over-  or
under-collections  of fuel and gas costs.  In addition,  the PUC may investigate
outages of  electric  generating  units  which  exceed 120 days or if the annual
capacity  factor of a unit is less  than 50% to  determine  whether  to deny the
recovery of replacement power costs.

     The Company's ECA provides for recovery of 100% of the  difference  between
the  Company's  PUC-  jurisdictional  costs  of  fuel,  energy  interchange  and
purchased  power and the costs billed to  customers in base rates.  The ECA also
incorporates a nuclear  performance  standard which allows for financial bonuses
or penalties  depending on whether the Company's  system nuclear capacity factor
exceeds or falls below a specified  range.  If the capacity factor is within the
range  of 60% to 70%,  there  is no bonus or  penalty.  If the  capacity  factor
exceeds 70%, then progressive  bonuses are allowed. If the capacity factor falls
below 60%, then progressive  penalties are imposed. The bonuses or penalties are
based upon average system  replacement energy costs. For the year ended December
31, 1995, the Company's  system nuclear  capacity factor was 72%, which entitled
the Company to a bonus of $2.5 million.

     On March 6, 1996, the Company filed its new ECA to become  effective  April
1, 1996. The ECA filing  proposes a change from a credit value of 5.086 mils per
kWh to a credit  value of 4.424 mils per kWh,  which  represents  a decrease  in
annual revenue of $21.7 million.  The ECA filing reflects a settlement agreement
with the Office of Consumer Advocate,  the Office of Small Business Advocate and
a group of the  Company's  industrial  customers,  which was filed with the ECA,
under which recovery of $33.1 million of replacement power costs associated with
the  shutdown  of Salem  would be denied  for the  reconciliation  period  ended
January 31, 1996, offset by an additional $6 million adjustment to the Company's
nuclear  performance  bonus.  The  approval  of the  ECA,  including  the  joint
settlement agreement, is pending before the PUC.

                                       13
<PAGE>
     On May 31, 1995,  the Company  filed  Purchased Gas Cost (PGC) No. 12 rates
for the period  December 1, 1995 through  November 30, 1996,  which  reflected a
$0.80 per  thousand  cubic feet (mcf)  decrease in natural gas sales  rates.  On
November 13, 1995, the PUC approved the Joint Settlement setting a $0.88 per mcf
decrease,  effective December 1, 1995, representing a decrease in annual revenue
of $48.4 million. Effective March 1, 1996, the first quarterly adjustment of the
PGC resulted in an increase of $0.335 per mcf in natural gas sales rates.

     The Company is  authorized  under a general order of the PUC to add a State
Tax Adjustment Surcharge to customers' bills to reflect the cost of increases or
decreases in certain state tax rates not recovered in base rates.

     On October 2, 1990,  the PUC issued an order  initiating  an  investigation
into Demand-Side Management (DSM) by electric utilities. Generally, DSM programs
involve utilities  providing  assistance or incentives to customers to encourage
them to conserve  energy and reduce peak  demand.  On December 1, 1993,  the PUC
issued  an order  establishing  a  special  DSM  cost-recovery  mechanism  for a
five-year period.  The PUC order would have permitted  surcharge recovery of DSM
program costs and allowed  utilities to earn an incentive on kWh saved from DSM.
The PUC order also would have permitted utilities to defer "lost revenues," with
interest,  for eventual recovery in the next base rate case. On January 9, 1995,
the  Commonwealth  Court  issued a decision  in which it upheld the PUC's  order
related to  surcharge  recovery of DSM program  costs,  but  reversed  the PUC's
decision to award DSM incentives  through a surcharge.  The  Commonwealth  Court
also  remanded  all  issues  related  to "lost  revenue"  recovery  for  further
consideration  by the PUC. The PUC appealed the decision to the Supreme Court of
Pennsylvania which affirmed the Commonwealth Court's decision.

     In  addition  to the  matters  discussed  above,  see  "Competition"  for a
discussion of the PUC's investigation of electric power competition issues.

Construction

     The Company maintains a construction program designed to meet the projected
requirements of its customers and to provide service reliability,  including the
timely replacement of existing  facilities.  The Company's current  construction
program  includes no new generating  facilities.  During the five years 1991-95,
gross property additions (excluding capital leases) amounted to $2.6 billion and
retirements   amounted  to  $272  million,   resulting  in  a  net  increase  of
approximately 17% in the Company's gross utility plant.  Investment in new plant
and  equipment  in  1995  amounted  to  $480  million.  At  December  31,  1995,
construction work in progress, excluding nuclear fuel, aggregated $494 million.

     The following  table shows the Company's  most recent  estimates of capital
expenditures for plant additions and improvements for 1996 and for 1997-99:

<TABLE>
<CAPTION>
                                                  (Millions of $)
                                                1996          1997-99
<S>                                            <C>           <C>   
     Electric:
          Production ..................        $  158        $  402
          Nuclear fuel ................            67           139
          Transmission and distribution           117           280
          Other electric ..............             2             9
                                               ------        ------
              Total electric ..........           344           830
     Gas ..............................            55           158
     Other ............................           139           254
                                               ------        ------
          Total .......................        $  538        $1,242
                                               ======        ======
</TABLE>

     Nuclear fuel  requirements  exclude the Company's share of the requirements
for Peach  Bottom and Salem which are  provided by an  independent  fuel company
under a capital lease. See note 16 of Notes to Consolidated Financial Statements
included in the Company's Annual Report to Shareholders for the year 1995.

                                       14
<PAGE>
Capital Requirements and Financing Activities

     The following  table shows the Company's  most recent  estimates of capital
requirements for 1996 and for 1997-99:

<TABLE>
<CAPTION>
                                                            (Millions of $)
                                                         1996         1997-99
<S>                                                     <C>           <C>   
     Construction ..............................        $  538        $1,242
     Long-term debt maturities and sinking funds           401           867
                                                        ------        ------
              Total capital requirements .......        $  939        $2,109
                                                        ======        ======
</TABLE>

     The Company expects to meet its capital  requirements,  including long-term
debt  maturities,  for 1996  with  internally  generated  funds  and  short-term
borrowings;  however, for 1997-99 the Company expects internally generated funds
to  more  than  satisfy  its  capital  requirements   including  long-term  debt
maturities. The estimates of capital requirements do not include any amounts for
unscheduled  refundings of  higher-dividend  preferred stock or  higher-interest
debt,  which  refundings are dependent on future market  conditions and internal
cash generation.

     The following table shows the Company's financing activities for 1995:
<TABLE>
<CAPTION>
                                                       (Millions of $)
<S>                                                     <C>
     Term Loan:
         Floating Rate due 1997 ...................        $175
     Trust Receipts, each representing a Company
         Obligated Mandatorily Redeemed
         Preferred Securities of a Partnership (1):
              8.72% ...............................          81
     Pollution Control:
         Floating Rate due 1996 ...................           8
                                                           ----
                                                           $264
                                                           ====
<FN>
---------------
(1)  Issued  through  PECO  Energy  Capital,  L.P.,  of  which  a  wholly  owned
     subsidiary of the Company is the general partner.
</FN>
</TABLE>

     The  long-term  debt and the  Trust  Receipts  (recorded  in the  financial
statements as Company Obligated  Mandatorily  Redeemed Preferred Securities of a
Partnership)  issued  during 1995 replaced  debt and  preferred  stock  carrying
higher  after-tax  rates of interest and  dividends.  During  1995,  the Company
utilized  cash  from  operations,  proceeds  from  the  sale  of its  subsidiary
Conowingo Power Company and $100 million from the sale of an undivided  interest
in trade receivables to reduce debt by $401 million.

     Under the Company's mortgage (Mortgage),  additional mortgage bonds may not
be issued on the basis of property  additions or cash deposits  unless  earnings
before income taxes and interest  during 12 consecutive  calendar  months of the
preceding  15 calendar  months from the month in which the  additional  mortgage
bonds are issued  are at least two times the pro forma  annual  interest  on all
mortgage bonds  outstanding  and then applied for. For the purpose of this test,
the Company has not included Allowance for Funds Used During  Construction which
is included in net income in the Company's  consolidated financial statements in
accordance  with the  prescribed  system of  accounts.  The  coverage  under the
earnings test of the Mortgage for the 12 months ended December 31, 1995 was 4.94
times.  Earnings  coverages  under the Mortgage for the calendar  years 1994 and
1993 were 3.48 and 4.20 times,  respectively.  At December  31,  1995,  the most
restrictive  issuance  test  of  the  Mortgage  related  to  available  property
additions.  At December  31,  1995,  the  Company had at least $1.44  billion of
available  property additions against which $864 million of mortgage bonds could
have been issued. In addition,

                                       15
<PAGE>
at December  31,  1995,  the Company was  entitled to issue  approximately  $3.5
billion of mortgage bonds without regard to the earnings and property  additions
tests against previously retired mortgage bonds.

     Under  the  Company's   Amended  and  Restated  Articles  of  Incorporation
(Articles),  the issuance of additional  preferred stock requires an affirmative
vote of the holders of  two-thirds of all preferred  shares  outstanding  unless
certain tests are met.  Under the most  restrictive  of these tests,  additional
preferred  stock may not be issued  without  such a vote unless  earnings  after
income taxes but before  interest on debt during 12 consecutive  calendar months
of the  preceding  15  calendar  months  from the month in which the  additional
shares of stock are issued are at least 1.5 times the aggregate of the pro forma
annual  interest and preferred stock dividend  requirements on all  indebtedness
and preferred  stock.  Coverage under this earnings test of the Articles for the
12 months ended  December 31, 1995 was 2.74 times.  Earnings  coverage under the
Articles  for the  calendar  years  1994 and  1993  was  2.05  and  2.47  times,
respectively.

     The following  table sets forth the  Company's  ratios of earnings to fixed
charges and the ratios of earnings to combined fixed charges and preferred stock
dividends for the periods indicated:

<TABLE>
<CAPTION>
                                                              1991         1992        1993        1994         1995
<S>                                                           <C>          <C>         <C>         <C>         <C> 
Ratio of Earnings to Fixed Charges.....................       2.55         2.43        3.15        2.66        3.49
Ratio of Earnings to Combined Fixed Charges and
     Preferred Stock Dividends.........................       2.14         2.06        2.67        2.32        3.18
</TABLE>

For purposes of these  ratios,  (i) earnings  consist of income from  continuing
operations  before income taxes and fixed charges and (ii) fixed charges consist
of all interest  deductions  and the  financing  costs  associated  with capital
leases.

     At December 31, 1995,  the Company had a total of $517 million  outstanding
under unsecured  term-loan  agreements  with banks with maturities  extending to
1997.  Most of the Company's  unsecured debt  agreements  contain  cross-default
provisions to the Company's other debt obligations.

     The Company has a $300 million commercial paper program supported by a $400
million  revolving  credit  agreement.  At  December  31,  1995,  there  was  no
commercial  paper  outstanding.  At  December  31,  1995,  the  Company  and its
subsidiaries had formal and informal lines of credit with banks aggregating $221
million  against which there was no short-term debt  outstanding.  The Company's
bank lines are comprised of both committed and uncommitted  lines of credit.  As
of December 31, 1995, the Company had no  compensating  balance  agreements with
any bank.


Employee Matters

     The Company and its  subsidiaries had 7,217 employees at December 31, 1995.
None of the  Company's  employees  are  represented  by a union.  In 1993,  in a
National  Labor  Relations  Board  (NLRB)  certified  election,  a  majority  of
non-management employees voted to continue not to be represented by a union.

     On March 7, 1995, a New Jersey local of the  International  Brotherhood  of
Electrical  Workers  (IBEW)  filed  two  petitions  with  the  NLRB  to  hold  a
certification   election  to  determine   whether  a  group  of  production  and
maintenance employees from Eddystone and Cromby want the IBEW to represent them.
The petitions seek to establish separate bargaining units for 225 employees from
Eddystone and 70 employees from Cromby.  The petitions cover craft and technical
employees,  including  operators,  but exclude  office  clerical,  professional,
supervisory and management employees.

     On March 22, 1995,  the Utility  Workers Union of America,  AFL-CIO  (UWUA)
filed a petition  with the NLRB to hold a  certification  election to  determine
whether  certain  production  and  maintenance  employees  from Peach Bottom and
Limerick want the UWUA to represent  them. The petition seeks a bargaining  unit
of

                                       16
<PAGE>
approximately  600  employees  composed  of all  maintenance  employees  and all
control room and  alternate  control room  operators  and  auxiliary  operators,
instrumental  and control  technicians,  health physics  technicians,  chemistry
technicians,  material handlers and technicians,  and rad waste technicians. The
petition excludes security guards,  clerical and supervisory employees. On March
23,  1995,  the NLRB  issued  an  order  consolidating  for  hearing  the  three
petitions.  From April through September,  the NLRB conducted hearings regarding
the appropriateness of the petitioned units and the eligibility issues for those
units. The Company has taken the position that the only  appropriate  bargaining
unit is the same  system-wide  unit that was  certified by the NLRB for the 1993
election,  and that it will oppose any attempt by outside  interests to organize
its employees. An NLRB decision is pending.

     On  October 2, 1995,  ten days  after the record in  proceedings  discussed
above were closed,  the UWUA filed another petition  seeking  certification of a
bargaining unit  consisting of all production and  maintenance  employees of the
Consumer Energy Services Group. The Company unsuccessfully sought to consolidate
this petition with the other three petitions. Hearings regarding the latest UWUA
petition are scheduled to begin in April 1996.


Environmental Regulations

     Environmental  controls at the  federal,  state,  regional and local levels
have a  substantial  impact  on the  Company's  operations  due to the  cost  of
installation  and  operation of  equipment  required  for  compliance  with such
controls.  In addition to the matters discussed below, see "Electric  Operations
-- General" and "Electric Operations -- Limerick Generating Station."

     An  environmental  issue with  respect to  construction  and  operation  of
electric  transmission  and  distribution  lines and other facilities is whether
exposure to electric and  magnetic  fields  (EMF)  causes  adverse  human health
effects.  A large number of  scientific  studies have examined this question and
certain  studies  have  indicated  an  association  between  exposure to EMF and
adverse  health  effects,  including  certain  types  of  cancer.  However,  the
scientific community still has not reached a consensus on the issue.  Additional
research  intended to provide a better  understanding  of EMF is continuing.  On
January 11, 1995,  researchers at the University of North Carolina  released the
results of an EMF study in which the Company had  participated.  The researchers
stated  that this study does not  resolve  the  fundamental  question of whether
magnetic fields cause cancer. The Company supports further research in this area
and is funding, monitoring and participating in such studies. The Company cannot
predict  at this time  what  effect,  if any,  this  matter  will have on future
operations.

     Public  concerns  about the possible  health risks of exposure to EMF have,
and are  expected  in the  future  to,  adversely  affect the costs of, and time
required  to, site new  distribution  and  transmission  facilities  and upgrade
existing facilities.

Water

     The Company has been informed by PSE&G that PSE&G is implementing  the 1994
New Jersey Pollutant Discharge  Elimination System permit issued for Salem which
requires,  among other things,  water intake screen  modifications  and wetlands
restoration.  In addition,  PSE&G is seeking  permits and approvals from various
agencies  needed to fully  implement the special  conditions  of the permit.  No
assurances  can be  given  as to  receipt  of any  such  additional  permits  or
approvals.  The estimated  capital cost of  compliance  with the final permit is
approximately  $100  million,  of which the  Company's  share is  42.59%  and is
included in the Company's capital requirements for 1996 and 1997-98.  PSE&G must
apply to renew the Salem  permit in March 1999 which  renewal  application  must
provide  updated  demonstrations  for  review by the New  Jersey  Department  of
Environmental Protection and Energy (NJDEPE).

Air

     Air  quality   regulations   promulgated  by  the  PDEP  and  the  City  of
Philadelphia in accordance with the federal Clean Air Act impose restrictions on
emission of particulates,  sulfur dioxide (SO2) and other pollutants and require
permits for  operation of emission  sources.  Such permits have been obtained by
the Company and must

                                       17
<PAGE>
be  renewed   periodically.   Under  the  Clean  Air  Act   Amendments  of  1990
(Amendments), new permits will have to be obtained.

     The Amendments  establish a comprehensive  and complex  national program to
substantially reduce air pollution over the next decades. The Amendments include
a  two-phase  program  to reduce  acid rain  effects by  significantly  reducing
emissions of SO2 and nitrogen oxides (NOx) from electric power plants.  Flue-gas
desulfurization systems (scrubbers) have been installed at Conemaugh Units No. 1
and No. 2 to reduce SO2 emissions to meet the 1995 Phase I  requirements  of the
Amendments.  The Company's share of the capital costs to construct the scrubbers
and make other related  improvements at Conemaugh was approximately $78 million.
Units No. 1 and No. 2 at Keystone are subject to the Phase II SO2 and NOx limits
of the  Amendments  which must be met by January 1, 2000.  The  Company  and the
other  Keystone  co-owners are  evaluating  the Phase II compliance  options for
Keystone, including the purchase of SO2 emission allowances and the installation
of scrubbers.

     The Company's  service-area,  coal-fired  generating units at Eddystone and
Cromby are equipped with scrubbers and their SO2 emissions meet the SO2 emission
rate  limits of both Phase I and Phase II of the  Amendments.  The  Company  has
completed the  implementation  of measures,  including the  installation  of NOx
emissions  controls and the imposition of certain  operational  constraints,  to
comply with the  Reasonably  Available  Control  Technology  limitations  of the
Amendments.  The Company's  capital  expenditures  to satisfy  these  compliance
requirements were  approximately $19 million.  The Company expects that the cost
of compliance with  anticipated  air-quality  regulations  may be  substantially
higher due to further limitations on permitted NOx emissions. As a result of its
prior  investments  in scrubbers for Eddystone and Cromby and its  investment in
nuclear  and  hydroelectric  generating  capacity,  the  Company  believes  that
compliance with the Amendments  will have less impact on the Company's  electric
rates than on the rates of other Pennsylvania utilities which are more dependent
on coal-fired generation.

     Many other provisions of the Amendments affect the Company's business.  The
Amendments  establish  stringent new control measures for  geographical  regions
which have been  determined by the EPA to not meet National  Ambient Air Quality
Standards;  establish limits on the purchase and operation of motor vehicles and
require  increased use of alternative  fuels;  establish  stringent  controls on
emissions of toxic air pollutants and provide for possible future designation of
some  utility   emissions  as  toxic;   establish  new  permit  and   monitoring
requirements  for  sources  of air  emissions;  and  provide  for  significantly
increased enforcement power, and civil and criminal penalties.

Solid and Hazardous Waste

     The Comprehensive Environmental Response,  Compensation,  and Liability Act
of  1980  and  the  Superfund   Amendments  and   Reauthorization  Act  of  1986
(collectively  CERCLA)  authorize  the  EPA to  cause  "potentially  responsible
parties"  (PRPs) to conduct  (or for the EPA to  conduct  at the PRPs'  expense)
remedial  action at waste  disposal  sites that pose a hazard to human health or
the environment.  Parties contributing  hazardous substances to a site or owning
or operating a site  typically  are viewed as jointly and  severally  liable for
conducting or paying for  remediation  and for  reimbursing  the  government for
related costs incurred.  PRPs may agree to allocate  liability among themselves,
or a court may perform that  allocation  according to equitable  factors  deemed
appropriate.  In addition,  the Company is subject to the Resource  Conservation
and Recovery Act (RCRA) which governs  treatment,  storage and disposal of solid
and hazardous wastes.

     By notice  issued in November  1986,  the EPA notified  over 800  entities,
including  the  Company,  that they may be PRPs  under  CERCLA  with  respect to
releases of radioactive  and/or toxic  substances  from the Maxey Flats disposal
site, a low-level  radioactive  waste  disposal site near  Moorehead,  Kentucky,
where  Company  wastes were  deposited.  Approximately  90 PRPs,  including  the
Company,  formed a steering committee and entered into an administrative consent
order with the EPA to conduct a remedial  investigation  and  feasibility  study
(RI/FS), which was substantially revised based on the EPA comments. In September
1991, following public review and comments,  the EPA issued a Record of Decision
in which it selected a natural stabilization remedy for the Maxey

                                       18
<PAGE>
Flats  disposal site. The steering  committee has  preliminarily  estimated that
implementing  the EPA proposed remedy at the Maxey Flats site would cost $60-$70
million in 1993  dollars.  A  settlement  has been reached  among the PRPs,  the
federal and private PRPs,  the  Commonwealth  of Kentucky and the EPA concerning
their respective roles and responsibilities in conducting remedial activities at
the site.  Under the  settlement,  the  private  PRPs will  perform  the initial
remedial  work  at the  site  and  the  Commonwealth  of  Kentucky  will  assume
responsibility for long-range maintenance and final remediation of the site. The
Company  estimates that it will be responsible  for $600,000 of the  remediation
costs to be incurred by the private  PRPs.  On June 5, 1995,  a consent  decree,
which  included the terms of the  settlement,  was filed with the United  States
District  Court  for  the  Eastern  District  of  Kentucky.  The  United  States
Department of Justice,  following a public comment  period,  filed a motion with
the court for entry of the decree. The PRPs have entered into a contract for the
design  and  implementation  of the  remedial  plan  and  preliminary  work  has
commenced.

     By notice  issued in December  1987,  the EPA  notified  several  entities,
including the Company, that they may be PRPs under CERCLA with respect to wastes
resulting  from the treatment  and disposal of  transformers  and  miscellaneous
electrical equipment at a site located in Philadelphia,  Pennsylvania (the Metal
Bank of America site). Several of the PRPs, including the Company, have formed a
steering committee to investigate the nature and extent of possible  involvement
in this matter.  On May 29, 1991, a Consent Order was issued by the EPA pursuant
to which the  members of the  steering  committee  agree to perform the RI/FS as
described in the work plan issued with the Consent Order. The Company's share of
the cost of the RI/FS was  approximately  30%.  On October  14,  1994,  the PRPs
submitted  to the EPA the RI/FS which  identified  a range of possible  remedial
alternatives  for the site from taking no action to removal of  essentially  all
contaminated material with an estimated cost range of $2 million to $90 million.
On July 19, 1995,  the EPA issued a proposed  plan for  remediation  of the site
which involves removal of contaminated soil,  sediment and groundwater and which
the EPA estimates would cost approximately $17 million to implement.  On October
18, 1995,  the PRPs  submitted  comments to the EPA on the  proposed  plan which
identified   several   inadequacies   with  the  plan,   including   substantial
underestimates  of the costs  associated with  remediation.  Until the Record of
Decision  has been issued by the EPA, the Company  cannot  estimate its share of
the cost to implement the selected remedy.

     By notice  issued in September  1985,  the EPA notified the Company that it
has been identified as a PRP for the costs associated with the cleanup of a site
(Berks  Associates/Douglasville  site) where waste oils  generated  from Company
operations were transported,  treated,  stored and disposed. In August 1991, the
EPA filed suit in the United States  District Court for the Eastern  District of
Pennsylvania  (Eastern  District Court) against 36 named PRPs, not including the
Company,  seeking a declaration that these PRPs are jointly and severally liable
for  cleanup of the Berks  Associates/Douglassville  site and for costs  already
expended   by  the  EPA  on  the  site.   Simultaneously,   the  EPA  issued  an
Administrative  Order  against  the same named  defendants,  not  including  the
Company,  which requires the PRPs named in the Administrative  Order to commence
cleanup of a portion of the site.  On September  29,  1992,  the Company and 169
other parties were served with a third-party  complaint joining these parties as
additional  defendants.  Subsequently,  an additional 150 parties were joined as
defendants. A group of approximately 100 PRPs with allocated shares of less than
1%,  including the Company,  have formed a negotiating  committee to negotiate a
settlement  offer with the EPA. In December  1994, the EPA proposed a de minimis
PRP settlement which would require the Company to pay approximately  $800,000 in
exchange  for the EPA  agreeing  not to sue,  take  administrative  action under
CERCLA for recovery of past or future response costs or seek  injunctive  relief
with  respect to the site.  The Company has  notified  the EPA that it wishes to
participate  with  other  eligible  PRPs in the de  minimus  settlement,  and is
currently awaiting approval of the settlement.

     In  June  1989,  a  group  of  PRPs  (Metro  PRP  Group)  entered  into  an
Administrative Order on Consent (AOC) with the EPA pursuant to which they agreed
to perform  certain  removal  activities at the Metro  Container  Superfund Site
located in Trainer,  Pennsylvania. In January 1990, the Metro PRP Group notified
the Company that the group  considered the Company to be a PRP at the site based
on evidence which it believes  indicates between 200 and 300 empty Company drums
were  transported  to the site.  The Company was invited to  participate  in the
allocation  process and was further informed that,  unless it agreed to sign the
AOC, the Company risked either being named in a cost recovery  action brought by
the EPA or in a  contribution  action  to be filed by the Metro  PRP  Group.  In
response, the Company notified the Metro PRP Group that it would be

                                       19
<PAGE>
interested in participating in the allocation  process.  The Metro PRP Group has
proposed a settlement  which would involve the Company  paying less than $10,000
towards  the  costs of a  removal  action  estimated  to cost  approximately  $5
million.  The Company has requested  additional  information  from the Metro PRP
Group.

     In October 1995, the Company, along with over 500 other companies, received
a General  Notice from the EPA advising that the Company had been  identified as
having sent  hazardous  substances  to the  Spectron/Galaxy  Superfund  Site and
requesting  the  companies  to conduct  an RI/FS at the site.  The  Company  had
previously  been  identified  as a de minimus  PRP and paid  $2,100 to settle an
earlier phase. Additionally, the Company had participated in a PRP agreement and
consent order related to further work at the Spectron site. In conjunction  with
the EPA's  General  Notice,  the  existing  PRP group has  proposed a settlement
which, based on the volume of hazardous  substances sent to the Spectron site by
the Company,  would allow the Company to settle the matter as a de minimus party
for less than $10,000.

     In April 1990, the Company  received a notice from the NJDEPE which alleges
that  the  Company  is  potentially  liable  for  certain  cleanup  costs at the
Gloucester  Environmental  Management Services,  Inc. (GEMS) site located in New
Jersey because  wastes  generated by the Company were deposited at the site by a
third  party.  The Company was added as a defendant  in a suit  commenced by the
NJDEPE several years ago, which now names several hundred defendants,  and which
relates to the GEMS site.  The Company has joined a  pre-existing  group of PRPs
which is dealing with the NJDEPE on these matters.  Settlement  negotiations are
ongoing. In February 1995, the Company was named as an additional defendant in a
private party class action seeking  damages  associated  with the GEMS site. The
Company settled the private party class action for $52,500.

     On October 16, 1989, the EPA and the NJDEPE commenced a civil action in the
United  States  District  Court  for  the  District  of New  Jersey  against  26
defendants,  not including  the Company,  alleging the right to collect past and
future  response costs for cleanup of the Helen Kramer  landfill  located in New
Jersey.  In October 1991, the direct  defendants joined the Company and over 100
other parties as third-party defendants.  The third-party complaint alleges that
the  Company  generated  materials  containing  hazardous  substances  that were
transported  to and disposed at the  landfill by a third  party.  The direct and
third-party  defendants  are  presently  involved  in  settlement   negotiations
involving an allocation process.

     In November 1987, the Company  received  correspondence  from the EPA which
indicated that the EPA was  investigating  the source,  extent and nature of the
release  or  threatened  release  of  hazardous  substances  from the  Blosenski
Landfill located in West Caln Township, Chester County,  Pennsylvania (Blosenski
Landfill  Superfund  Site).  The EPA  letter  requested  information  on several
Blosenski  entities and  affiliates  (Blosenski  entities)  and also whether any
wastes  generated by the Company had been  transported  to,  stored,  treated or
disposed at the Blosenski  Landfill Superfund Site. In January 1988, the Company
notified the EPA that,  after searching its files and records,  it was unable to
locate  or  identify  any  information  related  to the  Blosenski  entities  or
activities conducted at the Blosenski Landfill Superfund Site. Subsequently,  on
July 8, 1992,  the Company was  notified by a group of PRPs who had been ordered
by the EPA to implement one portion of the four-part remedial plan for the site,
that based on  information  which it  believed  indicated  Company  wastes  were
disposed of at the site, the group  considered the Company to be responsible for
a share of the cleanup and remediation  costs. The PRP group advised the Company
that unless it  voluntarily  joined the existing PRP group,  the Company  risked
being  named as a  defendant  in a  contribution  lawsuit  which had been  filed
against  certain other PRPs in federal  court.  On August 3, 1992, the PRP group
served the Company  with a subpoena  which  required the  production  of Company
documents  and  records  relating  to  Company  operations  and  waste  disposal
practices and procedures.  In September 1992, the Company informed the PRP group
that due to its inability to identify any pertinent  records in its own files or
confirm the PRP group's  allegations,  that it did not, at that time,  intend to
join the  Blosenski  PRP  Group  or  contribute  to the  remediation  costs.  In
addition,  the Company  submitted  documentation  which responded to some of the
subpoena  requests  and notified  the PRP group of its  objection to others.  On
September 7, 1995,  the federal court  approved a consent  decree which required
the site owner and  approximately  20 PRPs to implement an estimated $13 million
remedy at the site and reimburse the federal  government and the Commonwealth of
Pennsylvania  $5  million  for past  costs and  oversight  costs  related to the
cleanup.

                                       20
<PAGE>
     In November 1992, the Company  received a subpoena from the  non-government
parties (party participants) in a consolidated action relating to the Bridgeport
Rental and Oil  Services  (BROS)  site which  requested  information  on various
haulers who  transported  hazardous and solid waste  materials to the BROS site.
Information  gathered pursuant to the subpoena indicates that one of the haulers
associated with the BROS site picked up and  transported  waste generated by the
Company.  Additionally,  the party participants  possess  information which they
believe  connects  the  Company  to the  site.  At the  invitation  of the party
participants,  the Company along with several others (voluntary participants) is
participating  in a  "voluntary,  informal,  non-litigated  settlement/mediation
process." In April 1993, the Company received a Request for Information from the
EPA regarding the Company's  potential  involvement at the BROS site. On May 27,
1993, the Company provided the EPA with the same documents  gathered in response
to the subpoena served by the party participants. The voluntary participants are
presently engaged in negotiations with the party participants.

     On March 3, 1989, the Company  received a Notice of Violation from the PDEP
for soil  contamination  at one of the  Company's  maintenance  facilities.  The
Company  suspects that the  contamination  was caused by leakage of  transformer
dielectric  fluid.  The PDEP  required  the  Company  to  initiate  sampling  to
determine the scope of the  contamination.  The Company  conducted  sampling and
ground water  monitoring  and  submitted the results to the PDEP on November 18,
1991.  The  Company  has  identified  the  presence  of oil and  polychlorinated
byphenols (PCBs) at the site. On February 19, 1993, the Company submitted to the
PDEP a revised remedial clean-up  strategy.  On March 9, 1993, the PDEP accepted
the Company's  revised remedial clean-up  strategy.  The Company is implementing
the remedial  clean-up  strategy accepted by the PDEP, which is expected to cost
approximately $2 million over a period of three to five years.

     On November 30, 1995,  the Company was added as a third party  defendant in
an existing suit alleging that the Company is  responsible  for sending waste to
the  Cinnaminson  Ground  Water  Contamination  Site  located in the Township of
Cinnaminson  in Burlington  County,  New Jersey.  The Company  joined with other
third party  defendants  in filing a motion to dismiss the complaint for failure
to state a claim.  While  the  parties  await a ruling by the  court,  they will
participate  in a  court-ordered  mediation  process.  The Company is  currently
unable to estimate the cost of any potential corrective action.

     The Company has been named as a defendant in a Superfund  matter  involving
the Greer  Landfill  in South  Carolina.  The Company is  currently  involved in
settlement  discussions  with the plaintiff.  The Company is currently unable to
estimate the cost of any potential corrective action.

     The Company has  identified  23 sites where former  manufactured  gas plant
activities may have resulted in site  contamination.  Past activities at several
sites 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.  Seven of the sites are  currently  in the detailed  evaluation  or
remediation  stage. At December 31, 1995, the Company had accrued  approximately
$13 million for  investigation  and remediation of these  manufactured gas plant
sites.  The  Company  expects  that it will incur  additional  liabilities  with
respect to these sites, which cannot be reasonably estimated at this time.

     The  Company  has  also   responded  to  various   governmental   requests,
principally those of the EPA pursuant to CERCLA, for information with respect to
the possible deposit of Company waste materials at various disposal,  processing
and other sites.

     On June 4, 1993, the Company entered into a Corrective Action Consent Order
(CACO)  from the EPA  under  RCRA.  The  CACO  order  requires  the  Company  to
investigate the extent of alleged  releases of hazardous  wastes and to evaluate
corrective measures,  if necessary,  for a site located along the Delaware River
in Chester,  Pennsylvania,  which had previously been leased to Chem Clear, Inc.
Chem Clear operated an industrial waste water pretreatment facility on the site.
In October 1994, the Company  entered into an agreement with Clean Harbors,  the
successor to Chem Clear,  pursuant to which the Company will be responsible  for
approximately 25%

                                       21
<PAGE>
of the costs incurred  under the CACO and Clean Harbors will be responsible  for
75% of the costs.  The Company  estimates  that its share of the costs to comply
with the CACO will be  approximately  $2.5  million.  At December 31, 1995,  the
Company had spent $1.0 million to comply with the CACO.  Until completion of the
required investigation,  the Company is unable to predict the nature and cost of
any potential corrective action.

Costs

     At  December  31,  1995,  the  Company  had accrued $27 million for various
investigation and remediation costs that can be reasonably estimated,  including
approximately   $13  million  for   investigation   and  remediation  of  former
manufactured gas plant sites.  The Company cannot  currently  predict whether it
will incur  other  significant  liabilities  for  additional  investigation  and
remediation costs at sites presently identified or additional sites which may be
identified by the Company,  environmental agencies or others or whether all such
costs will be recoverable through rates or from third parties.

     The Company's budget for capital  requirements for 1996 and its most recent
estimate of capital  requirements for 1997-98 for compliance with  environmental
requirements  total $80 million.  This estimate  includes the Company's share of
the costs to comply  with the  revised  NJDEPE  permit for  Salem,  but does not
include any amounts  that may be required  for its share of  scrubbers  or other
systems at Keystone to comply with the Amendments.  In addition, the Company may
be  required  to  make   significant   additional   expenditures  not  presently
determinable.


Competition

     Over the last few years,  legislative and regulatory initiatives and market
forces have laid the foundation for continued  development of competition in the
electric  utility  industry.  As a result,  the  electric  utility  industry  is
reviewing the potential  impacts of a major  transition from a traditional  rate
regulated  environment  of bundled  service  based on cost recovery to unbundled
services with some  combination of a competitive  marketplace for some services,
principally  generation,  and  modified  regulation  of other  market  segments.
Increased  competition  is expected  to reduce the margin on certain  classes of
energy  sales  and  may  result  in  customer  and  revenue  losses.   Increased
competition  may also limit  high cost  utilities'  ability  to recover  capital
investment  through  rates,  resulting  in  stranded  investment  and  potential
writedown of assets.  Potential  competition  has resulted in increased focus on
cost cutting and consideration of strategic alternatives,  including mergers and
restructuring of operations.  For additional information concerning competition,
see  "Competition"  in the  "Management's  Discussion  and Analysis of Financial
Condition  and  Results  of  Operations"  in  the  Company's  Annual  Report  to
Shareholders for the year 1995.

     The  Energy  Act was  enacted  to promote  competition  among  utility  and
nonutility  generators in the wholesale  electric  generation market. The Energy
Act allows the FERC to order owners of electric  transmission systems to provide
third parties with transmission access for wholesale power transactions.  During
1995, the FERC issued proposed rules which,  if adopted,  would require that all
public  utilities  have on file  with  the  FERC  nondiscriminatory  open-access
transmission tariffs for network and point-to-point services, including separate
rates for ancillary  services.  The FERC's proposed rules would also provide for
recovery of legitimate  and  verifiable  wholesale  stranded  investment.  These
proposals further expressed the FERC's strong  expectation that state regulatory
commissions  provide for similar  full  recovery of  legitimate  and  verifiable
stranded  investment that could result if state regulatory  commissions  ordered
retail  competition and direct access. The Company filed comments in response to
the FERC's proposal. The comments, while generally supportive, suggested several
adjustments to ensure full stranded investment recovery.  An order from the FERC
is expected in the first half of 1996.

     The Company also filed a tariff for network and point-to-point services and
a market-based rate tariff that would allow the Company to sell wholesale energy
at  market-based  rates  outside the PJM control  area.  These  tariffs would be
available to wholesale  buyers and sellers of electricity,  although the Company
would  continue  to make sales  within the PJM control  area under its  existing
FERC-approved cost-based tariffs. The market-based

                                       22
<PAGE>
tariff  described above is not expected to affect the  applicability of SFAS No.
71,  "Accounting  for the  Effects  of  Certain  Types  of  Regulation,"  to the
Company's  operations.  For additional  information  concerning SFAS No. 71, see
"Management's  Discussion  and  Analysis of Financial  Condition  and Results of
Operations" in the Company's Annual Report to Shareholders for the year 1995.

     During  1995,  the Company  proposed a plan to enable the PJM  companies to
offer  regional  open  access  to their  transmission  facilities,  to create an
independent system operator, to adapt the existing PJM regional wholesale energy
market to increased  competition and to preserve those elements of power pooling
which are still beneficial.

     While the Energy Act  encourages  competition  on a  wholesale  level,  the
Energy  Act  prohibits  the FERC  from  ordering  wheeling  for  sales to retail
customers.  Currently, a number of states, including Pennsylvania, are assessing
the issue of retail  competition  with varying  outcomes.  While assessing their
positions,  many  issues  must be  considered  which  will  require  significant
deliberation  and may  result in legal  challenges.  These  issues  include  the
recovery   of   any    resulting    stranded    investment,    the   impact   of
inter-jurisdictional  sales and whether such change is enacted by  regulatory or
legislative action.

     In August  1995,  after  seeking  input  from  Pennsylvania  utilities  and
interest  groups,  the PUC  staff  issued  a  report  recommending  against  the
implementation  of retail electric power  competition at this time. The PUC also
issued  an  order  inviting  further  comments  and  establishing   hearings  on
competition   issues  with  the  expectation  of  submitting  a  report  to  the
Pennsylvania  legislature  and the Governor in June 1996. In November  1995, the
Company submitted  testimony which proposes five major initiatives to reduce the
costs of electricity while preserving the reliability and universal service that
is essential to Pennsylvania citizens. These initiatives are: 1) improvements in
the PJM  interconnection to incorporate an independent system operator,  provide
for wholesale  energy  exchange based on a market bidding  mechanism,  provide a
regional  transmission  tariff and expand  participation in the wholesale energy
market  to  others,  including  firms  that are not  traditional  utilities;  2)
performance-based  regulation  which would link utility  earnings to performance
rather than  historic  costs;  3) flexible  pricing to allow  utilities to offer
customers a variety of service options tailored to individual  requests,  and to
bring certain rates closer to market  levels;  4) accelerated  depreciation  and
other cost  mitigation  measures that challenge the utilities to reduce possible
stranded   investment   associated  with  existing  generation  assets;  and  5)
competitive  bidding  of  new  generation  to  ensure  that  needs  are  met  as
efficiently as possible.  The Company  believes that these proposed  initiatives
will allow the PUC to improve the  efficiency  of the electric  industry,  while
continuing to assure the  availability of reliable  service for all customers at
reasonable  rates,  without  significant  adverse  consequences on the financial
condition of the electric utilities.

     The Company  believes that retail  competition  should not be adopted if it
represents a mere shifting of costs from one class of customers to another or to
shareholders,  and that  retail  competition  does not  currently  provide a net
benefit.  Regulatory  changes  permitting  retail  competition  may also  create
stranded investment if the FERC's position of allowing full recovery of stranded
investment  as  described in its  proposal is not  adopted.  Investments  by the
Company in assets which would not be recoverable  from customers,  including its
investment in nuclear facilities,  may have to be written down, which would have
a material  adverse effect on the Company's  financial  condition and results of
operations.  The Company is not able to predict whether retail  competition will
be implemented  and, if implemented,  what impact it would have on the Company's
financial condition or results of operations.

     As a result of competitive pressures,  the Company has negotiated long-term
contracts with many of its larger- volume industrial  customers.  Although these
agreements  have resulted in lower  revenues from this class of customers,  they
have permitted the Company to maintain this segment of its customer base.

     The gas industry is also undergoing  structural changes in response to FERC
policies  designed to increase  competition  in this  market.  This has included
requirements that interstate gas pipelines unbundle their gas sales service from
other  regulated  tariff  services,  such  as  transportation  and  storage.  In
anticipation of these policies,

                                       23
<PAGE>
the Company has modified its gas purchasing  arrangements to enable the purchase
of gas and transportation at lower costs, and has become more active in the area
of gas transportation.

     During 1995, there were an  unprecedented  number of mergers in the utility
industry  and this trend is expected to continue.  In August  1995,  the Company
proposed a merger with PP&L Resources, Inc., an electric utility with operations
in northeast  Pennsylvania.  In November,  PP&L Resources declined the Company's
final offer and the Company withdrew its proposal.  The Company will continually
evaluate all  opportunities  to improve its strategic and  competitive  position
but, because of its strong stand-alone position, is not compelled to pursue such
opportunities at any cost.


Telecommunications

     To take  advantage  of  emerging  opportunities  in the  telecommunications
field,  in  1995,  the  Company  created  a new  strategic  business  unit,  the
Telecommunications Group. The business unit has initiated several joint ventures
in newly emerging wireless personal communications services businesses and other
competitive  telecommunications   opportunities.  The  telecommunications  field
presents the Company with many opportunities to expand its business and generate
additional revenues.


PECO Energy Capital Corp. and Related Entities

     PECO Energy Capital Corp., a wholly owned  subsidiary,  is the sole general
partner  of  PECO  Energy  Capital,   L.P.,  a  Delaware   limited   partnership
(Partnership).  The  Partnership  was created  solely for the purpose of issuing
preferred securities,  representing limited partnership  interests,  and lending
the  proceeds  thereof to the  Company,  and  entering  into  similar  financing
arrangements.  Such  loans  to  the  Company  are  evidenced  by  the  Company's
subordinated debentures,  which are the only assets of the Partnership. The only
revenues  of  the  Partnership  are  interest  on  the  Company's   subordinated
debentures  (Subordinated  Debentures).  All of the  operating  expenses  of the
Partnership  are paid by PECO Energy  Capital  Corp.  At December 31, 1995,  the
Partnership  held  $308,612,964  aggregate  principal amount of the Subordinated
Debentures.

     PECO  Energy  Capital  Trust I (Trust)  was  created in  October  1995 as a
statutory  business trust under the laws of the State of Delaware solely for the
purpose of issuing trust receipts (Trust  Receipts),  each representing an 8.72%
Cumulative  Monthly  Income  Preferred  Security,  Series B (Series B  Preferred
Securities) of the Partnership.  The Partnership is the sponsor of the Trust. On
December 19, 1995, the Trust issued  3,124,183 Trust  Receipts.  At December 31,
1995, the assets of the Trust consisted  solely of 3,124,183  Series B Preferred
Securities  with an aggregate  stated  liquidation  preference  of  $78,104,575.
Distributions  were made on the  Trust  Receipts  on  December  29,  1995 in the
aggregate  amount of  $1,074,893,  or $0.3441  per Trust  Receipt.  The  payment
reflects  accrued  distributions at the rate of 7.96% per annum from November 1,
1995 through  December 18, 1995 and at the rate of 8.72% per annum from December
19,  1995  through  December  31,  1995.  Expenses  of the  Trust  for 1995 were
approximately $2.1 million,  all of which were paid by PECO Energy Capital Corp.
or the  Company.  The number of holders  of record of the Trust  Receipts  as of
March 20, 1996 was 884.

                                       24
<PAGE>
Executive Officers of the Registrant

<TABLE>
<CAPTION>
                                  Age at                                                     Effective Date of Election
Name                           Dec. 31, 1995                Position                             to Present Position

<S>                                 <C>    <C>                                                   <C>
J. F. Paquette, Jr.............     61     Chairman of the Board...............................  April 12, 1995
C. A. McNeill, Jr..............     56     President and Chief Executive Officer...............  April 12, 1995
D. M. Smith....................     62     President-- PECO Nuclear and Chief
                                               Nuclear Officer.................................  February 1, 1996
W. L. Bardeen..................     57     Senior Vice President and Group Executive--
                                               Consumer Energy Services Group..................  March 1, 1994
J. W. Durham...................     58     Senior Vice President and General Counsel...........  October 24, 1988
W. J. Kaschub..................     53     Senior Vice President-- Human Resources.............  June 10, 1991
G. S. King.....................     55     Senior Vice President-- Corporate and
                                               Public Affairs..................................  October 1, 1992
K. G. Lawrence.................     48     Senior Vice President-- Finance and Chief
                                               Financial Officer...............................  March 1, 1994
J. M. Madara, Jr...............     52     Senior Vice President and Group
                                               Executive-- Power Generation Group..............  March 1, 1994
R. J. Patrylo..................     49     Senior Vice President and Group
                                               Executive-- Gas Services Group..................  August 1, 1994
G. R. Rainey...................     46     Senior Vice President-- Nuclear Operations..........  April 1, 1996
A. J. Weigand..................     57     Senior Vice President and Group
                                               Executive-- Bulk Power Enterprises .............  March 1, 1994
J. M. Bauer....................     49     Vice President-- Customer Services..................  April 13, 1994
G. A. Cucchi...................     46     Vice President-- Planning and Performance...........  March 1, 1994
D. B. Fetters..................     44     Vice President-- Station Support....................  September 25, 1995
D. R. Helwig...................     44     Vice President-- Power Delivery.....................  March 1, 1995
T. P. Hill, Jr.................     47     Vice President and Controller.......................  January 1, 1991
K. C. Holland..................     43     Vice President-- Information Systems
                                               and Chief Information Officer...................  March 21, 1994
W. G. MacFarland, IV...........     46     Vice President-- Limerick Generating
                                               Station.........................................  March 1, 1995
J. B. Mitchell.................     47     Vice President-- Finance and Treasurer..............  December 1, 1994
W. E. Powell, Jr...............     59     Vice President-- Support Services...................  January 30, 1995
T. N. Mitchell.................     40     Vice President-- Peach Bottom Atomic
                                               Power Station...................................  April 1, 1996
W. H. Smith, III...............     47     Vice President and Group Executive,
                                               Telecommunications Group........................  September 25, 1995
D. A. Thomas...................     49     Vice President-- Marketing and Sales................  January 30, 1995
N. J. Zausner..................     42     Vice President-- Power Transactions.................  October 11, 1994
K. K. Combs....................     45     Corporate Secretary.................................  November 1, 1994
</TABLE>

     The present term of office of each of the above executive  officers extends
to the first meeting of the Company's  Board of Directors  after the next annual
election of Directors (scheduled to be held April 10, 1996).

     Prior  to his  election  to his  current  position  with the  Company,  Mr.
Paquette was Chairman and Chief Executive Officer of the Company.

     Prior to his election to his current position with the Company, Mr. McNeill
was President and Chief Operating Officer and Executive Vice President - Nuclear
of the Company.

     Prior to his election to his current position with the Company, Mr. Bardeen
was Senior Vice President Finance and Chief Financial Officer.  Prior to joining
the Company in 1992, Mr.  Bardeen was Vice President  Finance and Controller for
Bell Atlantic Corporation.

                                       25
<PAGE>
     Prior to joining the Company in 1991,  Mr.  Kaschub was Vice  President  of
Human Resources with GTE North Incorporated.

     Prior to joining the Company in 1992,  Mrs. King served as  Commissioner of
the United States Social Security Administration.

     Prior  to his  election  to his  current  position  with the  Company,  Mr.
Lawrence was Vice President - Gas Operations.

     Prior to his election to his current position with the Company,  Mr. Madara
was Vice President - Production,  Assistant Manager - Mechanical Engineering and
General Manager - Nuclear Quality Assurance.

     Prior to joining the Company in 1994, Mr. Patrylo was Senior Vice President
- Gas Services  Business Unit at Niagara Mohawk Power  Corporation and President
of RJP Associates, Inc., a business consulting firm.

     Prior to his election to his current  position with the Company,  Mr. D. M.
Smith  was  Senior  Vice  President  - Nuclear  Generation  Group,  Senior  Vice
President - Nuclear and Vice President - Peach Bottom Atomic Power Station.

     Prior to his election to his current position with the Company, Mr. Weigand
was Vice President - Transmission and Distribution Systems.

     Prior to joining the Company in March 1994,  Mrs.  Holland was  Director of
Technology  Services  and  Director  of  Business  Services  and  Operations  at
SmithKline Beecham, Inc.

     Prior to joining the Company in 1996, Mr. T.N.  Mitchell was Team Manager -
Institute of Nuclear Power  Operations  (INPO),  Director - Site  Engineering at
Peach  Bottom (on loan from INPO),  Department  Manager  Engineering  Support at
INPO,  Core Team  Member - Nuclear  Electric,  U.K.  (on loan  from  INPO),  and
Department Manager - Plant Analysis at INPO.

     Prior to joining  the  Company in 1995,  Mr.  Powell was Vice  President  -
Logistics with E.I. DuPont DeNemours & Co.

     Prior to joining the  Company in 1995,  Mr.  Thomas was  General  Manager -
American  Parts and Services,  Manager - Utility Parts Sales,  Manager - Gateway
Region - Utility  Sales,  and  Manager - Product  Services  at General  Electric
Company.

     Prior to joining the Company in 1994,  Ms.  Zausner was Vice  President  of
U.S. Generating Company, an independent power producer.

     Prior to  their  election  to the  positions  shown  above,  the  following
executive  officers held other positions with the Company since January 1, 1991:
Ms.  Bauer was  Operations  Manager - Montgomery  County  Division and Manager -
Nuclear Operations;  Mr. Cucchi was Director of System Planning and Performance;
Mr. Fetters was Director - Nuclear Engineering,  Director - Limerick Maintenance
and a project  manager;  Mr.  Helwig was Vice  President  - Limerick  Generating
Station and Vice  President - Nuclear  Engineering  and  Services;  Mr. Hill was
Controller;  Mr.  MacFarland was Outage  Director - Limerick,  Manager - Nuclear
Maintenance,  Manager - Peach Bottom  Installation  Division and Senior  Project
Manager - Limerick Nuclear  Engineering;  Mr. Mitchell was Director of Financial
Operations and Assistant Treasurer; Mr. Rainey was Vice President - Peach Bottom
Atomic Power  Station,  Vice  President - Nuclear  Services and Plant  Manager -
Eddystone  Generating  Station;  Mr. W. H.  Smith was Vice  President  - Station
Support, Vice President - Planning and Performance, Manager - Corporate Strategy
and  Performance,  General  Manager - Human  Resources,  Director - Organization
Change  Task Force and  Manager -  Purchasing;  and Ms.  Combs was an  Assistant
General Counsel.

     There are no family  relationships among directors or executive officers of
the Company.

                                       26
<PAGE>
ITEM 2.   PROPERTIES

     The principal  plants and properties of the Company are subject to the lien
of the Mortgage under which the Company's First and Refunding Mortgage Bonds are
issued.

     The  following  table  sets forth the  Company's  net  electric  generating
capacity by station at December 31, 1995:

<TABLE>
<CAPTION>
                                                                                     Net Generating     Estimated
                                                                                      Capacity (1)      Retirement
                 Station                                  Location                     (Kilowatts)         Year
<S>                                             <C>                               <C>                 <C>
Nuclear
   Limerick..................................    Limerick Twp., PA..............      2,170,000(2)     2024(3), 2029(3)
   Peach Bottom..............................    Peach Bottom Twp., PA..........        928,000(4)        2013, 2014
   Salem.....................................    Hancock's Bridge, NJ...........        942,000(4)        2016, 2020
Hydro
   Conowingo.................................    Harford Co., MD................        512,000            2014
Pumped Storage
   Muddy Run.................................    Lancaster Co., PA..............        880,000            2014
Fossil (Steam Turbines)
   Cromby  ..................................    Phoenixville, PA...............        345,000             2004
   Delaware..................................    Philadelphia, PA...............        250,000             (5)
   Eddystone.................................    Eddystone, PA..................      1,341,000      2009, 2010, 2011
   Schuylkill................................    Philadelphia, PA...............        166,000             (5)
   Conemaugh.................................    New Florence, PA...............        352,000(4)      2005, 2006
   Keystone..................................    Shelocta, PA...................        357,000(4)      2002, 2003
Fossil (Gas Turbines)
   Chester ..................................    Chester, PA....................         39,000             (5)
   Croydon...................................    Bristol Twp., PA...............        370,000             (5)
   Delaware..................................    Philadelphia, PA...............         60,000             (5)
   Eddystone.................................    Eddystone, PA..................         62,000             (5)
   Falls.....................................    Falls Twp., PA.................         48,000             (5)
   Moser.....................................    Lower Pottsgrove Twp., PA......         48,000             (5)
   Richmond..................................    Philadelphia, PA...............         96,000             (5)
   Schuylkill................................    Philadelphia, PA...............         30,000             (5)
   Southwark.................................    Philadelphia, PA...............         53,000             (5)
   Salem.....................................    Hancock's Bridge, NJ...........         16,000(4)          (5)
Fossil (Internal Combustion)
   Cromby  .................. ...............    Phoenixville, PA...............          2,700             (5)
   Delaware..................................    Philadelphia, PA...............          2,700             (5)
   Schuylkill................................    Philadelphia, PA...............          2,800             (5)
   Keystone..................................    Shelocta, PA...................          2,300(4)         2003
   Conemaugh.................................    New Florence, PA...............          2,300(4)         2006
                                                                                      ---------

       Total....................................................................      9,077,800
                                                                                      =========
<FN>
---------------
(1)  Summer rating.
(2)  Effective  January 24, 1996,  Limerick  Unit No. 1 was rerated to 1,115,000
     kilowatts,  making the entire station's capacity 2,230,000 kilowatts.  This
     rerate  increased  the  Company's  net  generating  capacity  to  9,137,800
     kilowatts.  
(3)  For depreciation accrual purposes only,  retirement dates have been reduced
     by 10 years. See "Rate Matters." 
(4)  Company  portion.  
(5)  Retirement  dates are under on-going  review by the Company.  Current plans
     call for the continued operation of these units beyond 1996.
</FN>
</TABLE>

                                       27
<PAGE>
       The  following  table sets forth the  Company's  major  transmission  and
distribution lines in service at December 31, 1995:

<TABLE>
<CAPTION>
     Voltage in Kilovolts (Kv)                Conductor Miles
     <S>                                        <C>
     Transmission:
         500 Kv ..............                       824
         220 Kv ..............                     1,746
         132 Kv ..............                       656
         66 Kv ...............                       646
         33 Kv and below .....                        37
     Distribution:
         33 Kv and below .....                    48,809
</TABLE>

     At December 31, 1995, the Company's principal electric  distribution system
included  11,770  pole-line  miles of overhead  lines and 20,673  cable miles of
underground cables.

     The  Company is in the midst of an ongoing  program  to  implement  a 33 Kv
distribution  system for a large portion of outlying suburban areas. These areas
are now primarily served by a combination of 4 Kv distribution  circuits,  which
are being phased out, and direct  connections  to 33 Kv  subtransmission  lines,
which are being  converted  to 33 Kv  distribution  circuits.  The new system is
designed to improve the Company's  ability to meet the growing load requirements
of suburban areas, improve system reliability and reduce service interruptions.

     The following table sets forth the Company's gas pipeline miles at December
31, 1995:

<TABLE>
<CAPTION>
                                   Pipeline Miles
<S>                                 <C>
     Transmission .....                  28
     Distribution .....               5,458
     Service piping....               4,401
                                      -----
         Total ........               9,887
                                      =====
</TABLE>

     The  Company  has  a  liquefied   natural  gas  facility  located  in  West
Conshohocken,  Pennsylvania  which has a storage capacity of 1,200,000 mcf and a
sendout capacity of 200,000 mcf/day and a propane-air  plant located in Chester,
Pennsylvania,  with a tank storage  capacity of 1,980,000  gallons and a peaking
capability of 30,000 mcf/day. In addition,  the Company owns 23 natural gas city
gate stations (including one temporary station) at various locations  throughout
its gas service territory.

     The Company owns an office building in downtown  Philadelphia,  in which it
maintains  its  headquarters,  and also owns or leases  elsewhere in its service
area a number  of  properties  which  are used for  office,  service  and  other
purposes.  Information  regarding  rental and lease  commitments is incorporated
herein by reference  to note 16 of Notes to  Consolidated  Financial  Statements
included in the Company's Annual Report to Shareholders for the year 1995.

     The Company  maintains  property  insurance  against  loss or damage to its
principal  plants and  properties  by fire or other  perils,  subject to certain
exceptions.  Although it is impossible to determine the total amount of the loss
that may result from an occurrence at a nuclear generating station,  the Company
maintains its $2.75  billion  proportionate  share for each  station.  Under the
terms of the various insurance  agreements,  the Company could be assessed up to
$46 million for property  losses  incurred at any plant insured by the insurance
companies  (see "ITEM 1.  BUSINESS  -- Electric  Operations  --  General").  The
Company is  self-insured  to the extent that any losses may exceed the amount of
insurance  maintained.  Any such losses, if not recovered through the ratemaking
process,  could  have a  material  adverse  effect  on the  Company's  financial
condition and results of operations.

                                       28
<PAGE>
ITEM 3.   LEGAL PROCEEDINGS

     On April 11,  1991,  33 former  employees  of the Company  filed an amended
class action suit against the Company in the Eastern District Court on behalf of
approximately 141 persons who retired from the Company between January and April
1990.  The lawsuit,  filed under the  Employee  Retirement  Income  Security Act
(ERISA), alleged that the Company fraudulently and/or negligently misrepresented
or concealed facts  concerning the Company's 1990 Early Retirement Plan and thus
induced the plaintiffs to retire or not to defer retirement  immediately  before
the  initiation  of the  1990  Early  Retirement  Plan,  thereby  depriving  the
plaintiffs  of  substantial  pension  and salary  benefits.  In June  1991,  the
plaintiffs filed amended  complaints adding additional  plaintiffs.  The lawsuit
named the  Company,  the  Company's  Service  Annuity Plan (SAP) and two Company
officers as  defendants.  On May 13, 1994,  the Eastern  District Court issued a
decision,  finding the Company liable to all plaintiffs who made inquiries about
any early  retirement plan after March 12, 1990 and retired prior to April 1990.
In an order dated  August 23,  1995,  the  Eastern  District  Court  awarded the
plaintiffs  $1.5  million.  The Company has filed appeals from the order and has
accrued the amount of the award.

     On May 2, 1991,  37 former  employees of the Company filed an amended class
action suit against the Company,  the SAP and three former  Company  officers in
the Eastern  District Court, on behalf of 147 former  employees who retired from
the Company between January and June 1987. The lawsuit was filed under ERISA and
concerned the August 1, 1987 amendment to the SAP. The  plaintiffs  claimed that
the Company concealed or  misrepresented  the fact that the amendment to the SAP
was planned to increase retirement benefits and, as a consequence,  they retired
prior to the  amendment to the SAP and were deprived of  significant  retirement
benefits. On May 13, 1994, the Eastern District Court issued a decision, finding
the  Company  liable to all  plaintiffs  who made  inquiries  about any  pension
improvement  after  March 1, 1987 and  retired  prior to June 1987.  In an order
dated August 23, 1995, the Eastern  District  Court awarded the plaintiffs  $1.8
million. The Company has filed appeals from the order and has accrued the amount
of the award.

     On May 25, 1993, the Company  received a letter from attorneys on behalf of
a shareholder  demanding  that the Company's  Board of Directors  commence legal
action  against  certain  Company  officers  and  directors  with respect to the
Company's  credit  and  collections  practices.  The basis of the demand was the
findings and conclusions  contained in the Credit and Collection  section of the
May 1991 PUC Management  Audit Report (Audit Report)  prepared by Ernst & Young.
At its June 28,  1993  meeting,  the  Board of  Directors  appointed  a  special
committee  of  directors  to consider  whether such legal action would be in the
best interests of the Company and its shareholders.  On March 14, 1994, upon the
recommendation  of the  special  committee,  the Board of  Directors  approved a
resolution  refusing the shareholder demand set forth in the May 25, 1993 demand
letter,  and authorizing and directing officers of the Company to take all steps
necessary to terminate the derivative suit discussed  below. On August 15, 1995,
attorneys on behalf of the shareholders  filed a derivative  action in the Court
of Common Pleas of  Philadelphia  County (Court of Common  Pleas)  asserting the
same claims against  several  present and former  officers which are asserted in
the July 26, 1993  shareholder  derivative suit discussed below. On February 20,
1996, the Court of Common Pleas ordered that the suit be  consolidated  with the
July 26, 1993  shareholder  derivative  suit. Any monetary  damages which may be
recovered,  net of expenses, would be paid to the Company because the lawsuit is
brought derivatively by shareholders on behalf of the Company.

     On  July  26,  1993,  attorneys  on  behalf  of two  shareholders  filed  a
shareholder  derivative  action in the Court of Common Pleas against  several of
the  Company's  present and former  officers  alleging  mismanagement,  waste of
corporate  assets and breach of fiduciary duty in connection  with the Company's
credit and collections  practices.  The derivative suit is based on the findings
and  conclusions  contained in the Credit and  Collections  section of the Audit
Report.  The  plaintiffs  seek,  among other things,  an  unspecified  amount of
damages and the awarding to the plaintiffs of the costs and disbursements of the
action,  including  attorneys'  fees.  A trial date has been set for November 4,
1996.  Any monetary  damages which may be recovered,  net of expenses,  would be
paid to the Company because the lawsuit is brought  derivatively by shareholders
on behalf of the Company.

     On March 5, 1996, the Company and Delmarva Power & Light Company (Delmarva)
filed an action in the United States District Court for the Eastern  District of
Pennsylvania against Public Service Enterprise Group

                                       29
<PAGE>
Incorporated and its subsidiary PSE&G (Enterprise Group) concerning the shutdown
of Salem; on the same date,  Atlantic Electric Company (Atlantic Electric) filed
a similar suit  against  Enterprise  Group in New Jersey  state court.  The suit
alleges that  Enterprise  Group breached the provisions of the Owners  Agreement
pursuant to which the four companies own Salem and under which  Enterprise Group
operates Salem. The suit also alleges  negligence,  gross negligence,  reckless,
and willful and wanton misconduct.  The plaintiffs seek compensation for certain
replacement  power costs they  incurred as a result of the shutdown of Salem and
for increased  operating and maintenance  costs and lost profits.  The complaint
does not specify any dollar amount of damages.

     During the shutdown of Salem,  examinations of the steam generator tubes at
Salem Unit No. 1 revealed  significant  cracking.  On  February  27,  1996,  the
Company, PSE&G, Atlantic Electric and Delmarva, the co-owners of Salem, filed an
action in the  United  States  District  Court for the  District  of New  Jersey
against Westinghouse Electric Corporation,  the designer and manufacturer of the
Salem steam  generators.  The suit alleges that the significant  cracking of the
steam  generator tubes is the result of defects in the design and fabrication of
the steam  generators  and that  Westinghouse  knew  that the  steam  generators
supplied to Salem were defective and that  Westinghouse  deliberately  concealed
this from PSE&G. The suit alleges  violations of both the federal and New Jersey
Racketeer  Influenced and Corrupt  Organizations Acts (RICO),  fraud,  negligent
misrepresentation and breach of contract.  For additional information concerning
the cracking of steam generator tubes at Salem, see "ITEM 1. BUSINESS - Electric
Operations - Salem Generating Station."

ITEM 4.   SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

     None.

                                     PART II

ITEM 5.   MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED
          STOCKHOLDER MATTERS

     The Company's common stock is listed on the New York and Philadelphia Stock
Exchanges.  At January  31,  1996,  there were  186,754  owners of record of the
Company's  common  stock.  The  information  with  respect  to the prices of and
dividends on the Company's  common stock for each  quarterly  period during 1995
and 1994 is  incorporated  herein by reference to "Operating  Statistics" in the
Company's Annual Report to Shareholders for the year 1995.

     The book value of the  Company's  common  stock at  December  31,  1995 was
$20.40 per share.

     Dividends  may be declared on common stock out of funds  legally  available
for  dividends  whenever  full  dividends  on  all  series  of  preferred  stock
outstanding at the time have been paid or declared and set apart for payment for
all past quarter-yearly dividend periods. No dividends may be declared on common
stock,  however,  at any time when the Company has failed to satisfy the sinking
fund  obligations  with  respect to certain  series of the  Company's  preferred
stock. Future dividends on common stock will depend upon earnings, the Company's
financial condition and other factors, including the availability of cash.

     The  Company's  Articles  prohibit  payment  of any  dividend  on, or other
distribution  to the holders of, common stock if, after giving  effect  thereto,
the capital of the Company  represented  by its common stock  together  with its
Other Paid-In Capital and Retained Earnings is, in the aggregate,  less than the
involuntary  liquidating  value  of its then  outstanding  preferred  stock.  At
December 31, 1995, such capital ($4.53  billion)  amounted to about 12 times the
liquidating value of the outstanding preferred stock ($292.1 million).

     The Company may not declare dividends on any shares of its capital stock in
the event  that:  (1) the  Company  exercises  its right to extend the  interest
payment  periods  on  the  Company's   subordinated   debentures   (Subordinated
Debentures)  which were issued to the  Partnership;  (2) the Company defaults on
its guarantee of

                                       30
<PAGE>
the  payment  of  distributions  on  the  Cumulative  Monthly  Income  Preferred
Securities  of the  Partnership;  or (3) an event of  default  occurs  under the
Indenture under which the Subordinated Debentures are issued.


ITEM 6.   SELECTED FINANCIAL DATA

     Selected financial data for each of the last five years for the Company and
its subsidiaries is incorporated  herein by reference to "Financial  Statistics"
and "Operating  Statistics" in the Company's  Annual Report to Shareholders  for
the year 1995.


ITEM 7.   MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
          RESULTS OF OPERATIONS

     The  information  with  respect to this caption is  incorporated  herein by
reference to  "Management's  Discussion and Analysis of Financial  Condition and
Results of Operations" in the Company's  Annual Report to  Shareholders  for the
year 1995.


ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

     The  information  with  respect to this caption is  incorporated  herein by
reference to "Consolidated  Financial Statements" and "Financial  Statistics" in
the Company's Annual Report to Shareholders for the year 1995.


ITEM 9.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
          FINANCIAL DISCLOSURE

     None.


                                    PART III

ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

     (a)  Identification of Directors.

     The  information  required for Directors is included in the Proxy Statement
of the Company in connection  with its 1996 Annual Meeting of Shareholders to be
held April 10, 1996,  under the heading  "Proposal 1. Election of Directors" and
is incorporated herein by reference.

     (b)  Identification of Executive Officers.

     The  information  required for Executive  Officers is set forth in "ITEM 1.
BUSINESS -- Executive Officers of the Registrant" of this Form 10-K.


ITEM 11.  EXECUTIVE COMPENSATION

     The  information  with  respect to this  caption is  included  in the Proxy
Statement  of the  Company  in  connection  with  its  1996  Annual  Meeting  of
Shareholders  to  be  held  April  10,  1996,   under  the  heading   "Executive
Compensation Disclosure" and is incorporated herein by reference.

                                       31
<PAGE>
ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     The  information  with  respect to this  caption is  included  in the Proxy
Statement  of the  Company  in  connection  with  its  1996  Annual  Meeting  of
Shareholders to be held April 10, 1996, under the heading  "Proposal 1. Election
of Directors" and is incorporated herein by reference.


ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

     The  information  with  respect to this  caption is  included  in the Proxy
Statement  of the  Company  in  connection  with  its  1996  Annual  Meeting  of
Shareholders to be held April 10, 1996, under the heading  "Proposal 1. Election
of Directors" and is incorporated herein by reference.

                                       32
<PAGE>
                                     PART IV

ITEM 14.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

Financial Statements and Financial Statement Schedule

<TABLE>
<CAPTION>
                                                                                                 Reference (Page)
                                                                                          Form 10-K        Annual Report
                             Index                                                      Annual Report     to Shareholders
<S>                                                                                       <C>            <C>
Data incorporated  by reference from the Annual Report to  Shareholders  for the
   year 1995:
     Report of Independent Accountants.............................................          --                  19
     Consolidated Statements of Income for the years ended
       December 31, 1995, 1994 and 1993............................................          --                  20
     Consolidated Statements of Cash Flows for the years ended
       December 31, 1995, 1994 and 1993............................................          --                  21
     Consolidated Balance Sheets as of December 31, 1995 and 1994..................          --                  22
     Consolidated Statements of Changes in Common Shareholders'
       Equity and Preferred Stock for the years ended
       December 31, 1995, 1994 and 1993............................................          --                  24
     Notes to Consolidated Financial Statements....................................          --                  25
Data submitted herewith:
     Report of Independent Accountants.............................................          34                  --
     Schedule II--    Valuation and Qualifying Accounts for the years
                      ended December 31, 1995, 1994 and 1993.......................          35                  --
</TABLE>


     All other  schedules  are omitted  since the  required  information  is not
present or is not present in amounts  sufficient  to require  submission  of the
schedule,  or because the information  required is included in the  consolidated
financial statements and notes thereto.

     With  the  exception  of the  consolidated  financial  statements  and  the
independent  accountants'  report listed in the above index and the  information
referred  to in  Items 1, 2, 5, 6, 7 and 8,  all of  which  is  included  in the
Company's  Annual Report to Shareholders  for the year 1995 and  incorporated by
reference into this Form 10-K Annual Report,  the Annual Report to  Shareholders
for the year 1995 is not to be deemed "filed" as part of this Form 10-K.

                                       33
<PAGE>
                        REPORT OF INDEPENDENT ACCOUNTANTS

To the Shareholders and Board of Directors
PECO Energy Company:

     Our report on the consolidated  financial statements of PECO Energy Company
has been  incorporated  by  reference in this Form 10-K from page 19 of the 1995
Annual Report to  Shareholders  of PECO Energy  Company.  In connection with our
audits of such financial statements,  we have also audited the related financial
statement schedule listed in the index in Item 14 of this Form 10-K.

     In our opinion,  the financial  statement  schedule referred to above, when
considered  in  relation  to the basic  financial  statements  taken as a whole,
presents  fairly,  in all  material  respects,  the  information  required to be
included therein.



COOPERS & LYBRAND L.L.P.


2400 Eleven Penn Center
Philadelphia, Pennsylvania
February 2, 1996

                                       34
<PAGE>
                  PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

                SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS

                             (Thousands of Dollars)

<TABLE>
<CAPTION>
              Column A                        Column B           Column C-Additions         Column D       Column E

                                                                            Charged to
                                             Balance at     Charged to         Other                      Balance at
                                            Beginning of     Costs and       Accounts      Deductions       End of
             Description                       Period        Expenses        -Describe    -Describe(1)      Period


                                        FOR THE YEAR ENDED DECEMBER 31, 1995

<S>                                           <C>             <C>           <C>             <C>             <C>    
ALLOWANCE FOR UNCOLLECTIBLE
   ACCOUNTS.............................      $16,500         $39,043       $  --           $34,683         $20,860
                                              -------         -------       --------        -------         -------
         TOTAL..........................      $16,500         $39,043       $  --           $34,683         $20,860
                                              =======         =======       ========        =======         =======



                                        FOR THE YEAR ENDED DECEMBER 31, 1994

ALLOWANCE FOR UNCOLLECTIBLE
   ACCOUNTS.............................      $15,086         $44,186       $  --           $42,772         $16,500
                                              -------         -------       --------        -------         -------
         TOTAL..........................      $15,086         $44,186       $  --           $42,772         $16,500
                                              =======         =======       ========        =======         =======


                                        FOR THE YEAR ENDED DECEMBER 31, 1993

ALLOWANCE FOR UNCOLLECTIBLE
   ACCOUNTS.............................      $17,916         $40,758       $  --           $43,588         $15,086
                                              -------         -------       --------        -------         -------
         TOTAL..........................      $17,916         $40,758       $  --           $43,588         $15,086
                                              =======         =======       ========        =======         =======
<FN>
---------------
(1)  Write-off of individual accounts receivable.
</FN>
</TABLE>

                                       35
<PAGE>
Exhibits

     Certain of the following  exhibits have been filed with the  Securities and
Exchange  Commission  (Commission)  pursuant  to the  requirements  of the  Acts
administered by the  Commission.  Such exhibits are identified by the references
following  the  listing  of each such  exhibit  and are  incorporated  herein by
reference  under Rule 24 of the  Commission's  Rules of Practice.  Certain other
instruments  which would  otherwise be required to be listed below have not been
so listed  because such  instruments  do not  authorize  securities in an amount
which exceeds 10% of the total assets of the Company and its  subsidiaries  on a
consolidated  basis  and the  Company  agrees  to  furnish  a copy  of any  such
instrument to the Commission upon request.

Exhibit No.      Description

       3-1    Amended  and  Restated  Articles of  Incorporation  of PECO Energy
              Company (1993 Form 10-K, Exhibit 3-1).

       3-2    Bylaws of the  Company,  adopted  February  26,  1990 and  amended
              January 24, 1994 (1993 Form 10-K, Exhibit 3-2).

       4-1    First  and  Refunding  Mortgage  dated  May 1,  1923  between  The
              Counties Gas and Electric Company (predecessor to the Company) and
              Fidelity Trust Company,  Trustee  (First  Fidelity Bank,  National
              Association, successor), (Registration No. 2-2881, Exhibit B-1).

       4-2    Supplemental  Indentures  to the  Company's  First  and  Refunding
              Mortgage:

<TABLE>
<CAPTION>
                  Dated as of                        File Reference                            Exhibit No.
                 <S>                                  <C>                                      <C>
                  May 1, 1927                          2-2881                                    B-1(c)
                  March 1, 1937                        2-2881                                    B-1(g)
                  December 1, 1941                     2-4863                                    B-1(h)
                  November 1, 1944                     2-5472                                    B-1(i)
                  December 1, 1946                     2-6821                                    7-1(j)
                  September 1, 1957                    2-13562                                   2(b)-17
                  May 1, 1958                          2-14020                                   2(b)-18
                  May 1, 1964                          2-25628                                   4(b)-21
                  October 1, 1967                      2-28242                                   2(b)-23
                  March 1, 1968                        2-34051                                   2(b)-24
                  May 1, 1970                          2-38849                                   2(b)-28
                  December 15, 1970                    2-41081                                   2(b)-29
                  December 15, 1971                    2-44195                                   2(b)-31
                  January 15, 1973                     2-49842                                   2(b)-33
                  March 1, 1981                        2-72802                                   4-46
                  March 1, 1981                        2-72802                                   4-47
                  November 15, 1984                    1984 Form 10-K                            4-2(a)
                  December 1, 1984                     1984 Form 10-K                            4-2(b)
                  May 15, 1985                         1985 Form 10-K                            4-2(a)
                  October 1, 1985                      1985 Form 10-K                            4-2(b)
                  November 1, 1986                     1986 Form 10-K                            4-2(c)
                  July 15, 1987                        Form 8-K dated July 21, 1987              4(c)-63
                  July 15, 1987                        Form 8-K dated July 21, 1987              4(c)-64
                  August 1, 1987                       33-17438                                  4(c)-65
                  October 15, 1987                     Form 8-K dated October 7, 1987            4(c)-66
                  October 15, 1987                     Form 8-K dated October 7, 1987            4(c)-67
                  April 15, 1988                       Form 8-K dated April 11, 1988             4(e)-68
</TABLE>

                                       36

<PAGE>
<TABLE>
<CAPTION>
                  Dated as of                        File Reference                            Exhibit No.
                 <S>                                  <C>                                      <C>
                  April 15, 1988                       Form 8-K dated April 11, 1988             4(e)-69
                  October 1, 1989                      Form 8-K dated October 6, 1989            4(e)-72
                  October 1, 1989                      Form 8-K dated October 18, 1989           4(e)-73
                  April 1, 1991                        1991 Form 10-K                            4(e)-76
                  December 1, 1991                     1991 Form 10-K                            4(e)-77
                  January 15, 1992                     Form 8-K dated January 27, 1992           4(e)-78
                  April 1, 1992                        March 31, 1992 Form 10-Q                  4(e)-79
                  April 1, 1992                        March 31, 1992 Form 10-Q                  4(e)-80
                  June 1, 1992                         June 30, 1992 Form 10-Q                   4(e)-81
                  June 1, 1992                         June 30, 1992 Form 10-Q                   4(e)-82
                  July 15, 1992                        June 30, 1992 Form 10-Q                   4(e)-83
                  September 1, 1992                    1992 Form 10-K                            4(e)-84
                  September 1, 1992                    1992 Form 10-K                            4(e)-85
                  March 1, 1993                        1992 Form 10-K                            4(e)-86
                  March 1, 1993                        1992 Form 10-K                            4(e)-87
                  May 1, 1993                          March 31, 1993 Form 10-Q                  4(e)-88
                  May 1, 1993                          March 31, 1993 Form 10-Q                  4(e)-89
                  May 1, 1993                          March 31, 1993 Form 10-Q                  4(e)-90
                  August 15, 1993                      Form 8-A dated August 19, 1993            4(e)-91
                  August 15, 1993                      Form 8-A dated August 19, 1993            4(e)-92
                  August 15, 1993                      Form 8-A dated August 19, 1993            4(e)-93
                  November 1, 1993                     Form 8-A dated October 27, 1993           4(e)-94
                  November 1, 1993                     Form 8-A dated October 27, 1993           4(e)-95
                  May 1, 1995                          Form 8-K dated May 24, 1995               4(e)-96
</TABLE>

       4-3    Deposit Agreement with respect to $7.96 Cumulative Preferred Stock
              (Form 8-K dated October 20, 1992, Exhibit 4-5).

       4-4    PECO Energy Company Dividend Reinvestment and Stock Purchase Plan,
              as amended  January 28, 1994  (Post-Effective  Amendment  No. 1 to
              Registration No. 33-43523, Exhibit 28).

       4-5    Indenture,  dated as of July 1,  1994,  between  the  Company  and
              Meridian Trust Company, as trustee (1994 Form 10-K, Exhibit 4-5).

       4-6    Deferrable Interest Subordinated Debenture  Certificate,  Series A
              (1994 Form 10-K, Exhibit 4-6).

       4-7    First  Supplemental  Indenture,  dated  as of  December  1,  1995,
              between the Company and Meridian  Trust  Company,  as trustee,  to
              Indenture dated as of July 1, 1994.

       4-8    Deferrable Interest Subordinated Debenture Certificates, Series B,
              No. 1 and No. 2.

       4-9    Payment and Guarantee Agreement,  dated July 27, 1994, executed by
              the Company in favor of the holders of Cumulative  Monthly  Income
              Preferred Securities,  Series A of PECO Energy Capital, L.P. (1994
              Form 10-K, Exhibit 4-7).

       4-10   Payment and  Guarantee  Agreement,  dated as of December 19, 1995,
              executed  by the  Company in favor of the  holders  of  Cumulative
              Monthly  Income  Preferred  Securities,  Series  B of PECO  Energy
              Capital, L.P.

                                       37
<PAGE>

       10-1   Pennsylvania-New  Jersey-Maryland  Interconnection Agreement dated
              September 26, 1956  (Registration No. 2-13340,  Exhibit 13-40) and
              agreements supplemental thereto:

<TABLE>
<CAPTION>
                  Dated as of                          File Reference                            Exhibit No.
                 <S>                                 <C>                                   <C>
                  March 1, 1965                        2-38342                                   5-1(a)
                  January 1, 1971                      2-40368                                   5-1(b)
                  June 1, 1974                         2-51887                                   5-1(c)
                  September 1, 1977                    1989 Form 10-K                            10-1(a)
                  October 1, 1980                      1989 Form 10-K                            10-1(b)
                  June 1, 1981                         1989 Form 10-K                            10-1(c)
</TABLE>

       10-2   Agreement, dated November 24, 1971, between Atlantic City Electric
              Company,  Delmarva Power & Light Company,  Public Service Electric
              and Gas Company and the Company  for  ownership  of Salem  Nuclear
              Generating  Station (1988 Form 10-K,  Exhibit 10-3);  supplemental
              agreement  dated  September 1, 1975;  and  supplemental  agreement
              dated January 26, 1977 (1991 Form 10-K, Exhibit 10-3).

       10-3   Agreement, dated November 24, 1971, between Atlantic City Electric
              Company,  Delmarva Power & Light Company,  Public Service Electric
              and Gas  Company and the Company  for  ownership  of Peach  Bottom
              Atomic Power Station;  supplemental  agreement  dated September 1,
              1975; and supplemental agreement dated January 26, 1977 (1988 Form
              10-K, Exhibit 10-4).

       10-4   Deferred  Compensation and Supplemental Pension Benefit Plan (1981
              Form 10-K, Exhibit 10-16).*

       10-5   Forms of Agreement between the Company and certain officers.

       10-6   PECO Energy Company  Long-Term  Incentive Plan  (Registration  No.
              333-451, Exhibit 99).*

       10-7   Amended and Restated Limited Partnership  Agreement of PECO Energy
              Capital, L.P., dated July 25, 1994 (1994 Form 10-K, Exhibit 10-7).

       10-8   Amendment  No. 1 to the Amended and Restated  Limited  Partnership
              Agreement of PECO Energy Capital, L.P.

       10-9   Amendment  No. 2 to the Amended and Restated  Limited  Partnership
              Agreement of PECO Energy Capital, L.P.

       10-10  Amended and Restated Trust  Agreement of PECO Energy Capital Trust
              I, dated as of December 19, 1995.

       10-11  Agreement  between the Company and Delmarva  Power & Light Company
              for the purchase  and sale of capacity  and energy,  dated May 24,
              1994 (1994 Form 10-K, Exhibit 10-9).

       12-1   Ratio of Earnings to Fixed Charges.

       12-2   Ratio  of  Earnings  to  Combined   Fixed  Charges  and  Preferred
              Stock Dividends.

       13     Management's  Discussion  and Analysis of Financial  Condition and
              Results of Operations, Consolidated Financial Statements, Notes to
              Consolidated  Financial  Statements,   Financial  Statistics,  and
              Operating  Statistics of the Annual Report to Shareholders for the
              year 1995.

                                       38
<PAGE>
       21     Subsidiaries of the Registrant.

       23     Consent of Independent Accountants.

       24     Powers of Attorney.

       27     Financial Data Schedule.

---------------
*    Compensatory  plans or  arrangements  in which directors or officers of the
     Company participate and which are not available to all employees.


Reports on Form 8-K

     During the quarter  ended  December 31,  1995,  the Company  filed  Current
Reports on Form 8-K, dated:

         October 17, 1995  reporting  information  under "ITEM 5. OTHER  EVENTS"
         relating to the shutdown of Salem Generating Station operated by Public
         Service Electric and Gas Company.

         October 23, 1995  reporting  information  under "ITEM 5. OTHER  EVENTS"
         relating to the proposed merger with PP&L Resources, Inc.

         November 1, 1995  reporting  information  under "ITEM 5. OTHER  EVENTS"
         relating to the proposed merger with PP&L Resources, Inc.

         December 11, 1995  reporting  information  under "ITEM 5. OTHER EVENTS"
         relating to the shutdown of Salem Generating Station operated by Public
         Service Electric and Gas Company.

     Subsequent to December 31, 1995, the Company filed a Current Report on Form
8-K, dated:

         February 23, 1996  reporting  information  under "ITEM 5. OTHER EVENTS"
         relating  to the  cracking  of steam  generator  tubes at Unit No. 1 at
         Salem  Generating  Station  operated by Public Service Electric and Gas
         Company.

                                       39
<PAGE>

                                   SIGNATURES

     Pursuant  to the  requirements  of  Section  13 or 15(d) of the  Securities
Exchange Act of 1934, the registrant,  PECO ENERGY COMPANY, has duly caused this
annual  report to be signed on its  behalf by the  undersigned,  thereunto  duly
authorized,  in the City of Philadelphia,  and Commonwealth of Pennsylvania,  on
the 27th day of March 1996.

                                        PECO ENERGY COMPANY

                                        By /s/ C.A. MCNEILL, JR.
                                        ----------------------------------------
                                        C.A. McNeill, Jr., 
                                        President and Chief Executive Officer

     Pursuant to the  requirements of the Securities  Exchange Act of 1934, this
annual  report has been signed below by the  following  persons on behalf of the
registrant and in the capacities and on the dates indicated.

<TABLE>
<CAPTION>
  Signature                                    Title                                Date
<S>                                     <C>                                     <C>

/s/ J. F. PAQUETTE, JR.
------------------------------------    Chairman of the Board and Director      March 27, 1996
    J. F. Paquette, Jr.


/s/ C. A. MCNEILL, JR.
-----------------------------------     President, Chief Executive Officer      March 27, 1996
C. A. McNeill, Jr.                      and Director (Principal Executive
                                        Officer)

/s/ K. G. LAWRENCE
-----------------------------------     Senior Vice President - Finance         March 27, 1996
K. G. Lawrence                          and Chief Financial Officer
                                        (Principal Financial and
                                        Accounting Officer)
</TABLE>



     This  annual  report  has also been  signed  below by C. A.  McNeill,  Jr.,
Attorney-in-Fact, on behalf of the following Directors on the date indicated:

          SUSAN W. CATHERWOOD                     JOSEPH C. LADD
          M. WALTER D'ALESSIO                     EDITHE J. LEVIT
          RICHARD G. GILMORE                      KINNAIRD R. MCKEE
          RICHARD H. GLANTON                      JOSEPH J. MCLAUGHLIN
          JAMES A. HAGEN                          JOHN M. PALMS
          NELSON G. HARRIS                        RONALD RUBIN
                                  ROBERT SUBIN

By /s/ C. A. MCNEILL, JR.                                        March 27, 1996
-----------------------------------
C. A. McNeill, Jr., Attorney-in-Fact