FORM 10-K
                  SECURITIES AND EXCHANGE COMMISSION

                     Washington, D.C. 20549

    (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

              Registrant; State of               I.R.S.Employer
Commission    Incorporation; Address;            Identification
File No       and Telephone Number               Number

1-9760        ATLANTIC ENERGY, INC.                 22-2871471
              (a New Jersey Corporation)
              6801 BLACK HORSE PIKE, 
              EGG HARBOR TOWNSHIP, NEW JERSEY 08234
              609-645-4500

1-3559        ATLANTIC CITY ELECTRIC COMPANY        21-0398280
              (a New Jersey Corporation)
              6801 BLACK HORSE PIKE 
              EGG HARBOR TOWNSHIP, NEW JERSEY 08234 
              609-645-4100

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

                                      Name of each exchange
Title of each class                   on which registered  

Common Stock, No Par Value            New York Stock Exchange 
of Atlantic Energy, Inc.              Philadelphia Stock Exchange
                                      Pacific Stock Exchange


Securities registered pursuant to Section 12(g) of the Act:  None

     Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the registrant was required to
file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes  X  No    


     Indicate by check mark if disclosure of delinquent filers
pursuant to Rule 405 of Regulation S-K is not contained herein,
and will not be contained, to the best of 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 10K.  X 

     Estimated aggregate market value of the voting stock of
Atlantic Energy, Inc. held by non-affiliates at March 4, 1996,
was $1,003,338,045.00 based on a closing price of $19.125 per
share for the 52,462,120 outstanding shares at such date. 
Atlantic Energy, Inc. owns all of the 18,320,937 outstanding
shares of Common Stock of Atlantic City Electric Company.

Documents Incorporated by Reference:

     Certain sections of the Notice of Annual Meeting of
Shareholders and Proxy Statement in connection with the     
Annual Meeting of Shareholders, to be held April 24, 1996, have
been incorporated by reference to provide information required by
the following parts of this report:

Part III-Item 10, Directors and Executive Officers of the
Registrant; Item 11, Executive Compensation; Item 12, Security
Ownership of Certain Beneficial Owners and Management; Item 13,
Certain Relationships and Related Transactions.  

This combined Form 10-K is filed separately by Atlantic Energy,
Inc. and Atlantic City Electric Company.  Information contained
herein relating to any individual registrant is filed by such
registrant on its own behalf.  Atlantic City Electric Company
makes no representation as to information relating to Atlantic
Energy, Inc.
<PAGE>
PART I
ITEM 1 BUSINESS                                             
General                                                   1 
Atlantic City Electric Company                            1      
Competition                                               2
Nonutility Subsidiaries                                   5
Construction and Financing                                7    
Rates                                                     9
Energy Requirements and Power Supply                     11  
Power Pool and Interconnection Agreements                12
Power Purchases and Sales                                13
Capacity Planning                                        13
Nonutility Generation                                    15       
Nuclear Generating Station Developments                  16
     Salem Station                                       19
     Hope Creek Station                                  24
     Peach Bottom                                        26
Fuel Supply                                              27
    Oil                                                  27
    Coal                                                 27
    Gas                                                  28
    Nuclear Fuel                                         28
Nuclear Decommissioning                                  30
Regulation                                               31
Environmental Matters                                    34
    General                                              34
    Air                                                  37
    Water                                                38
Executive Officers                                       41
ITEM 2   PROPERTIES                                      43
ITEM 3   LEGAL PROCEEDINGS                               43
ITEM 4   SUBMISSION OF MATTERS TO A VOTE OF SECURITY 
         HOLDERS                                         43
PART II                                                  43
ITEM 5   MARKET FOR REGISTRANT'S COMMON EQUITY AND 
         RELATED STOCKHOLDER MATTERS                     43
ITEM 6   SELECTED FINANCIAL DATA                         45
ITEM 7   MANAGEMENT'S DISCUSSION AND ANALYSIS OF
         FINANCIAL CONDITION AND RESULTS OF OPERATIONS   46
ITEM 8   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA     57
ITEM 9   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
         ON ACCOUNTING AND FINANCIAL DISCLOSURE          90
PART III                                                       
ITEM 10  DIRECTORS AND EXECUTIVE OFFICERS OF THE
         REGISTRANT                                      90
ITEM 11  EXECUTIVE COMPENSATION                          90
ITEM 12  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
         OWNERS AND MANAGEMENT                           90
ITEM 13  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS  90
PART IV                                                  90
ITEM 14  EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND
         REPORTS ON FORM 8-K                             90
SIGNATURES                                               92

                                     i<PAGE>
PART I
ITEM 1   BUSINESS



General

     Atlantic Energy, Inc. (AEI or the Company), the principal
office of which is located at 6801 Black Horse Pike, Egg Harbor
Township, New Jersey, 08232-4130, telephone 609-645-4500 was
organized under the laws of New Jersey in August 1986. The
Company is a public utility holding company as defined in the
Public Utility Holding Company Act of 1935 (PUHCA), and has
claimed an exemption from substantially all of the provisions of
the 1935 Act. For a complete description of the Company and its
subsidiaries, see Note 1 of the accompanying Notes to Financial
Statements herein.
                                
    Principal cash inflows of the Company include the receipt of
dividends from ACE and loans outstanding from a revolving credit
and term loan facility established by AEI in September 1995. As
of December 31, 1995, AEI has $34.5 million outstanding under
such facility.  Principal cash outflows of the Company in 1995
included capital contributions and advances to its subsidiaries,
the payment of dividends to common shareholders and the
repurchase of outstanding common stock.

Atlantic City Electric Company

     ACE, which has a wholly-owned subsidiary, Deepwater
Operating Company, is the principal subsidiary of the Company and
is engaged in the generation, transmission, distribution, and
sale of electric energy in the southern part of New Jersey. 
ACE's principal office is located at 6801 Black Horse Pike, Egg
Harbor Township, New Jersey, 08232-4130, telephone 609-645-4100,
and was organized under the laws of New Jersey on April 28, 1924,
by merger and consolidation of several utility companies.  ACE is
subject to regulation by the New Jersey Board of Public Utilities
(BPU) and the Federal Energy Regulatory Commission (FERC).  At
December 31, 1995, ACE had over 473,000 customers and employed
1,455 persons, of which 622 were affiliated with a national labor
organization.  With the exception of a municipal electric system
providing electric service within the municipal boundaries of the
City of Vineland, New Jersey, ACE supplies electric service to
the southern one-third of the State of New Jersey.  

     ACE is a utility whose peak load has occurred during the
summer months, and approximately 32% of 1995 revenues were
recorded during the quarter ended September 30, 1995.   

<PAGE>
Competition
     
     The electric utility industry continues to undergo a
fundamental transformation that is creating a power market
governed more by market forces than regulation.  Trends toward
open competition will continue to effect ACE's financial and
operational performance.  Specific competitive issues affecting
ACE include: the unbundling of energy supply services; an
increasingly competitive energy supply market; open access to
transmission facilities; heightened customer demand for
competitive services; the advancement of new technologies and
changes in utility regulation. 

     Significant changes in Federal and state regulations have
fostered an increase in competition among power generators and
have encouraged new entrants to the generation industry.  The
Public Utility Regulatory Policy Act (PURPA) created a new class
of generating facilities, operated by independent power producers
(IPPs), and required electric utilities to purchase the excess
power from each IPP.  As a direct result of PURPA, ACE is under
long-term contracts with four such IPP's for the purchase of 579
megawatts of capacity and energy.  ACE has experienced a
significant decline in its sales to industrial customers, three
of which contracted with IPP's for their power supply.  ACE has
subsequently regained one such customer through contract
renegotiation and expects to regain a second in 1996.
  
     The Energy Policy Act of 1992 (the Act) represented another
significant step toward deregulation of the electric utility
industry. The Act facilitated development of the wholesale power
market and increased competition between utility and non-utility
generators (NUGs).  The Act created a class of NUGs called exempt
wholesale generators that would be exempt from certain PUHCA
regulations.  The Act also gave FERC the authority to order open
access to the transmission facilities of electric utilities and
the wheeling of wholesale electric power.
  
     In response to the Act, in October of 1994, FERC issued a
pricing policy statement that became effective upon issue. The
statement is designed to provide the framework for developing
transmission pricing tariffs and contains several principles for
evaluation of proposals.  In March 1995 FERC issued a Notice of
Proposed Rulemaking (NOPR) that could impact several key
regulatory principles, including transmission access,
transmission pricing and recovery guidelines for stranded costs
stemming from wholesale transactions.  According to the NOPR,
within 60 days of passage of a final rule, nondiscriminatory
open-access transmission tariffs must be filed by ACE and all
other affected electric utilities.  The tariffs would be
applicable to all participants in the wholesale power market,
including utilities, NUGs, power marketers, municipalities and
cooperatives.  The NOPR requires utilities to offer transmission
service to eligible users, comparable to the service they provide
themselves and to take service under the tariffs for their own
wholesale sales and purchases of power. ACE expects to file an
open access tariff in compliance with FERC's proposed rules in
late March 1996.  A final FERC rulemaking is expected in the
second half of 1996.   

     Regarding the issue of stranded commitments and investments
that could arise from wholesale wheeling, the NOPR states that
utilities should be entitled to full recovery of legitimate and
verifiable stranded costs and that such costs should be assigned
to departing customers. The NOPR further states that stranded
costs due to any eventual retail wheeling should be addressed on
a state level, while stranded costs due to wholesale wheeling,
municipalization or a change from retail to wholesale customer
class are within FERC's jurisdiction.  Such stranded commitments
and investments could result from the development of market-based
wholesale or retail electric prices that do not support the full
recovery of investments such as generating and transmission
assets, regulatory assets or long-term purchase power contracts
with QFs that were placed into rates under traditional cost based
regulation.   
     
     The effects of an increasingly competitive utility
marketplace on ACE will also be determined by the timing of and
extent to which New Jersey utility regulations are modified to
reflect competitive industry trends.  The pace and degree of New
Jersey deregulation could also be influenced by competitive
regulatory developments in other state jurisdictions. The BPU's
on-going Energy Master Plan (EMP) proceeding's Phase I report,
issued  in March 1995, provides a framework for managing the
transition of the states's natural gas and electric power
industries from markets guided by regulation to those guided by
market-based principles and competition.  Phase II of the
proceeding is currently underway and is examining possible
structural changes to the state's electric utility industry. 
Phase II is evaluating the issues surrounding potential stranded
investment, direct access, retail wheeling, tax policies and
generation divestiture.  Reports are expected by late March 1996
to be followed by public hearings and a final report from the BPU
in the second quarter of 1996.  Phase III of the EMP will include
an assessment of prices, supply and use of various sources of
energy, including renewables and energy conservation, and will
assess energy usage by various sectors of the economy.  

     Legislation signed into law in New Jersey in July 1995,
allows the BPU, upon petition from any electric or gas utility,
to adopt a plan of regulation other than the traditional rate
base/rate of return regulation.  In addition, on a case by case
basis, the law allows utilities to petition the BPU for the right
to offer customers, who meet certain conditions, off-tariff,
discounted rates. The law provides for the recovery of up to 50
percent of the value of discounts in a subsequent base rate case
if it can be adequately demonstrated that the discount benefits
all ratepayers.  Specific off-tariff pricing arrangements with
ACE's customers will be limited by the resources available in the
Company's business plan.  For further information, refer to
"Rates" herein.
     
     Other proposed regulatory and accounting changes have been
suggested relating to matters at the state and Federal level
which could have operating and financial implications for ACE. 
See "Regulation" and "Environmental Controls" herein for
additional information and Note 10 of the accompanying Notes to
Financial Statements herein. 

     In response to the continuing competitive trends, the
Company has undertaken a number of initiatives to better position
its businesses for an open retail marketplace.  ACE and AEE are
carrying-out strategic plans designed to increase the
competitiveness of the core utility business while creating new
revenue and profit opportunities through the development of non-
regulated energy businesses and markets.  ACE is focusing on cost
and rate control measures as well as expanding its energy-related
product and service offers to enhance customer satisfaction and
loyalty.  AEE is investing in a number of energy-related markets
to further expand the Company's presence in the energy services
industry while enhancing total shareholder value.  During the
transition to a competitive industry the Company will actively
monitor and participate in regulatory initiatives that could
advance a more open marketplace.  In addition, the Company will
continually evaluate its strategies, structure and market
position with respect to competitive trends and developments in
the industry.  For further information regarding the Company's
competitive strategy refer to Item 7-Management's Discussion and
Analysis of Financial Condition and Results of Operation -
Outlook.                                                          
                                                                  
                                                                  
                                                                  
                                                                  
                                          <PAGE>
Nonutility Subsidiaries

Atlantic Energy Enterprises, Inc. (AEE)

     On January 1, 1995, the Company formed a subsidiary,
Atlantic Energy Enterprises, Inc., a holding company, to which
ownership of the existing non-utility businesses was transferred. 
AEE's business plan projects an investment of approximately $400
million over the next five years in these businesses.  
     
     The amount of capital invested by AEE in its non-utility
subsidiaries will be affected, to a large degree, by the rate of
development of the respective businesses, by the business
opportunities which may exist and by the opportunities for
external financings by such subsidiaries themselves.  For further
information, refer to Note 6 of the accompanying Notes to
Financial Statements herein.   

Atlantic Generation, Inc. (AGI)

     At December 31, 1995, AGI's activities were represented by
partnership interests in three cogeneration power projects:  
Project        Fuel       Capacity       Commercial     Ownership
Location       Type     Megawatt (MW)     Operation      Interest

Binghamton,    
New York        gas          50              1992      one-third
Pedricktown,
New Jersey      gas          117             1992      one-half
Vineland,
New Jersey      gas         46.5             1994      one-half

     Subsidiaries of Tristar Ventures Corporation, a subsidiary
of The Columbia Gas System, Inc. have partnership interests in
the Pedricktown, Binghamton and Vineland projects; subsidiaries
of Stone & Webster Development Corporation have a one-third
partnership interest in the Binghamton project.  The Binghamton
facility is hosted by a large paper manufacturer and supplies New
York State Gas and Electric with up to 40 MW of capacity and
related energy under a 15 year power purchase agreement.  The
Pedricktown facility is hosted by a chemical manufacturer and
during 1995 supplied 106 MW of capacity and related energy to ACE
under a 30 year contract.  In 1995, the BPU-approved an amendment
to this contract re-establishing the project host as a retail
customer of ACE and assigning an additional 10 MW of generating
capacity to ACE.  The Vineland facility is hosted by a food
processor and provides 46.5 MW of capacity and related energy to
the City of Vineland under a 25 year contract.  
     
     At December 31, 1995, total equity in AGI amounted to $26.1
million, the funding of which has been through capital
contributions and advances from the Company.  

ATE Investment, Inc. (ATE)

     ATE commenced activities in 1988.  At December 31, 1995, ATE
has invested $79 million in leveraged leases of three commercial
aircraft and two containerships.  ATE has issued $15 million
principal amount of long term debt and has utilized a revolving
credit and term loan agreement with a bank to finance a portion
of its investment in leveraged leases and other investment
activities.  The remainder is provided by capital contributions
from the Company.  At December 31, 1995, total equity amounted to
$9.4 million. 

Atlantic Southern Properties, Inc. (ASP) 

     ASP owns and manages a 280,000 square-foot commercial
property located in southern New Jersey.  Portions of the office
space are presently under lease to ACE and AEE.  At December 31,
1995, ASP's assets consisted primarily of this real estate site
at a net book value of $10.1 million.  Financing of ASP's
operations has been accomplished through capital contributions
and advances from the Company and loans from ATE.  At December
31, 1995, equity totalled $2.3 million.

Atlantic Energy Technology, Inc. (AET)

     AET has ceased operations and is currently concluding the
affairs of its wholly-owned subsidiary, which is its sole
investment. 

Atlantic Thermal Systems, Inc. (ATS)

     Formed in 1994, ATS and its wholly-owned subsidiaries
develop, own and operate thermal heating and cooling systems and
have invested $12 million as of December 31, 1995.  ATS is
currently developing a district heating and cooling system in
Atlantic City, New Jersey, construction of which is expected to
begin in 1996.  ATS has obtained funds for its project
development through advances and loans from the Company. 
Additional funds for the project, currently held in trust, are
expected through loans of proceeds from $12.5 million principal
amount of bonds issued by the New Jersey Economic Development
Authority.  At December 31, 1995, equity totalled $2.2 million.

CoastalComm, Inc. (CCI) 

     In November 1995, CCI was formed to pursue investments and
business opportunities in the telecommunications industry.  At
December 31, 1995, CCI had committed $5.2 million in a venture
pursuing markets in the personal communications systems business. 
 
<PAGE>
Atlantic CNRG Services, LLC 

     In addition to the existing non-utility subsidiaries, AEE
has a 50% ownership interest in Atlantic CNRG Services, LLC,
(ACNRG) a limited liability company that provides energy
management services, including natural gas procurement,
transportation and marketing.  On February 1, 1996, ACNRG
acquired certain assets of Interstate Gas Marketing Co., a
privately held company headquartered in Scranton, Pennsylvania. 
Assets purchased by ACNRG consisted primarily of gas marketing
contracts of commercial and industrial customers located
primarily in Pennsylvania.  The duration of acquired contracts
varies from one to five years. 
     
Construction and Financing

     ACE maintains a continuous construction program, principally
for electric generation, transmission and distribution
facilities.  The construction program, including the estimates of
construction expenditures, as well as the timing of construction
additions, is under continuous review.  ACE's construction
expenditures will depend upon factors such as long term load and
customer growth, general economic conditions, the ability of ACE
to raise the necessary capital, regulatory and environmental
requirements, the availability of capacity and energy from
utility and nonutility sources and the Company's return on such
investments.  Although deferrals in construction timing may
result in near-term expenditure reductions, changes in capacity
plans and general inflationary price trends could increase
ultimate construction costs.  Reference is made to "Energy
Requirements and Power Supply" herein for information with
respect to ACE's estimates of future load growth and capacity
plans.  The table below presents ACE's estimated cash
construction costs for utility plant for the years 1996 through
1998:
 
 (Millions of Dollars)       1996      1997     1998      Total
Nuclear Generating           $ 14      $  8     $  6       $ 28
Fossil Steam
 Generating                    11         6        9         26
Transmission and
 Distribution                  43        44       41        128
General Plant                  21        22       14         57
Combustion Turbine              3         5        8         16
Total Cash                  
 Construction Costs          $ 92      $ 85     $ 78      $ 255
                             ====      ====    =====       ====

     See "ATS" herein for additional information regarding
construction of a district heating and cooling facility in
Atlantic City, New Jersey.  For further information, see Note 5
of the accompanying Notes to Financial Statements herein.  

     On an interim basis, ACE finances that portion of its
construction costs and other capital requirements in excess of
its internally generated funds through the issuance of unsecured
short term debt, consisting of bank loans and commercial paper. 
ACE undertakes permanent financing through the issuance of long
term debt, preferred stock and/or capital contributions from the
Company.  Costs associated with ACE's share of nuclear fuel
requirements for the jointly-owned Peach Bottom, Salem and Hope
Creek generating stations have been financed by a non-affiliated
company which generally recovers its investment costs as nuclear
fuel is consumed for power generation.

     At December 31, 1995, ACE had available for use various bank
committed lines of credit totaling $150 million, which are
subject to continuing review and to termination by the banks
involved.  On December 31, 1995, ACE had short term borrowings of
$30.5 million outstanding.  Based on the above level of
construction expenditures, ACE currently estimates that during
the three-year period 1996-1998, it will issue, excluding amounts
issued for refunding purposes, approximately $150 million in
debt, including First Mortgage Bonds.  ACE also undertakes
refundings of existing securities to reduce its overall cost of
funds.  During 1995, ACE refunded and retired approximately $54.7
million principal amount of its First Mortgage Bonds.  Funds for
such redemptions were obtained through the issuance and sale by
ACE of $105 million of First Mortgage Bonds, designated as Medium
Term Notes (MTN).  Additional funds obtained from the sale of
MTNs were used for construction purposes.  Reference is made to
"Management's Discussion and Analysis of Financial Condition and
Results of Operations" and Notes 6 and 7 of the Notes to
Financial Statements, incorporated by reference herein as Exhibit
28(a), for information relating to ACE's financing activities for
the 1993-1995 period and for 1996-1998.  

     ACE's debt securities are currently rated "A-/A3" by two
major rating agencies.  Its preferred stock is rated "BBB+/Baa1"
and its commercial paper is rated "A-2/P2."  

     One rating agency has recently revised its outlook on ACE
from "stable" to "negative" to reflect the heightened concern
over the potentially adverse impact on credit quality of recently
discovered tube cracks in the steam generators at Unit 1 of the
two-unit Salem Nuclear Station.  See "Salem Station" for
additional information.   
  
     No assurances can be given that the ratings of ACE's
securities will be maintained or continue at their present
levels, or be withdrawn if such credit rating agency should, in
its opinion, take such action.  Downward revisions or changes in
ratings of a company's securities could have an adverse effect on
the market price of such securities and could increase a
company's cost of capital.  

Rates

     ACE's rates for retail electric service are subject to the
approval of the BPU.  For information concerning changes in base
rates and the levelized energy clause (LEC) for the years 1993
through 1995 and certain other proceedings relating to rates, see
"Purchased Power" herein and Notes 1, 3 and 8 of ACE's Notes to
Financial Statements, incorporated by reference herein as Exhibit
28(a). 

     A performance standard for ACE's five jointly-owned nuclear
units was adopted in 1987 by the BPU, with certain aspects of the
performance standards revised, effective January 1, 1990.  Under
the standard, the composite target capacity factor for such units
is 70%, based upon the maximum dependable capacity of the units. 
The zone of reasonable performance (deadband) is between 65% and
75%.  Penalties or rewards are based on graduated percentages of
estimated costs of replacement power.  Such amount is calculated
monthly, utilizing the average PJM monthly billing rate as the
cost basis for replacement power, to the boundaries of the
deadband, with penalties calculated incrementally in steps.  Any
penalties incurred are not permitted to be recovered from
customers and are required to be charged against income. 
Adjustments to rates based on the nuclear unit performance
standard is done through ACE's annually adjusted LEC.  

     The 1995 composite capacity factor for ACE's jointly-owned
nuclear units was 57.9%, resulting in an estimated penalty of
$1.3 million.  (See "Nuclear Generating Station Developments"
herein for additional information.)

     In February 1995, ACE filed a petition with the BPU
requesting approval of a pilot economic development power
contract program for large commercial and industrial customers
that would permit ACE to offer contracts for electric service on
a negotiated basis.  No formal action was taken by the BPU
regarding this filing.  The requested terms of the filing were
superseded by the regulations established through legislation
enacted in July 1995 that authorizes the BPU to approve alternate
forms of economic regulation and allows utilities to provide
discounted rates in order to retain large customers.  The law
provides for the recovery of up to 50 percent of the value of the
discount in a subsequent base rate case if it can be adequately
demonstrated that the discount benefits all ratepayers.  On
October 27, 1995, the BPU issued a summary decision to consider
and implement standards for off-tariff rate agreements which
incorporate, among other things, certain tests and conditions to
be satisfied prior to entering into such agreements.  Specific
off-tariff pricing arrangements with ACE's customers will be
limited by the resources available in the Company's business
plan.   
     
     On March 13, 1996, the BPU issued its decision making final
the provisional $37 million increase in LEC rates requested in 
April 1995.  For further information, see Note 3 of ACE's Notes
to Financial Statements, incorporated by reference herein as
Exhibit 28(a).

     ACE expects to file its LEC request for the period June 1,
1996 through May 31, 1997 with the BPU in April 1996.  ACE
expects to reflect in its filing a nuclear performance penalty of
$1.3 million associated with 1995 nuclear performance, which
amount would not be recovered from customers and has already been
charged against 1995 earnings.  At this time, the amount of its
LEC request for 1996/1997 has not been finalized.  

     By Order dated March 14, 1996, the BPU ordered ACE's base
rates related to Salem Unit 1 interim and subject to refund,
effective immediately, pending a full hearing as to whether Salem
I is currently used and useful.  The BPU ordered ACE to file
briefs within fifteen business days with regard to why the BPU
should not, after hearings, immediately declare base rates
related to Salem Unit 2 interim and subject to refund pending
hearings to determine if Salem Unit 2 is used and useful.  ACE is
also required to furnish, within fifteen business days, the
actual level of net plant investment associated with each of the
Salem units, based on ACE's last base rate case, the amount of
operating and maintenance expenses included in current base rates
for each unit, the level of replacement power costs associated
with the Salem outage to date and the amount of projected monthly
replacement power costs for the duration of the outage.  Separate
hearings will be held by the BPU regarding the issue as to
whether or not Salem Unit 1 and Salem Unit 2 are no longer used
and useful and the actual level of any appropriate rate
reduction.  For further information, see "Salem Station" herein.
 
     On January 16, 1996 Public Service Electric & Gas Company
(PS) filed a petition with the BPU requesting approval for an
alternate rate making methodology.  Included in PS's plan is a
proposal to implement an immediate rate reduction and a plan for
an indexed price cap mechanism, effective January 1, 1997.  PS's
plan also outlines certain categories of costs not subject to the
price cap index as well as certain economic development program
proposals, a mechanism to share productivity gains with customers
and depreciation changes affecting utility plant assets.  PS's
plan also proposes the elimination of PS' Nuclear Performance
Standard.  On January 25, 1996, ACE filed a motion to intervene
in the proceeding based on the effect the outcome of the PS
proceeding could have on ACE, including: tariff and rate matters;
depreciation, ownership and operation of jointly-held nuclear
generating facilities and flexible utility pricing.  At this time
ACE cannot predict the outcome of this proceeding.


Energy Requirements and Power Supply

     ACE's 1995 kilowatt-hour sales decreased by approximately
1.4% over 1994 sales.  Commercial sales grew by 1.4%, offset by
declines in residential and industrial sales of 2.0% and 7.4%,
respectively.  The 1995 utility systems' peak demand of 2,042 MW
occurred on July 15, 1995 and was 4.1% above the previous peak
demand recorded on July 10, 1993 of 1,962 MW.  

     For the five-year period of 1996 through 2000, ACE's
estimate of projected annual sales growth is 3.0% and peak load
growth (adjusted for weather) is 2.1%.  These include the
estimated effects of load-reducing cogeneration and demand-side
management programs.

     ACE has generally been able to provide for the growth of
energy requirements through the construction of additional
generating capacity, joint ownership in larger units and through
capacity purchases from other utilities and nonutilities.  The
net summer installed capacity, in kilowatt-hours (KW), of ACE at
December 31, 1995, consisted of the following:

                                       Year(s)     Net
Station and             Primary        Unit(s)     Capability
   Location              Fuels        Installed    (KW)       

Deepwater
 Salem Co., N.J.     Oil/Coal/Gas      1930/         54,000 
                                       1954-1958    166,000 
B.L. England
 Cape May Co., N.J.  Coal/Oil          1962-1964/   284,000
                                       1974         155,000
Keystone
  Indiana Co., PA.   Coal              1967-1968     42,000 (1)
Conemaugh
  Indiana Co., PA.   Coal              1970-1971     65,000 (1)
Peach Bottom
 York Co., PA.       Nuclear           1974         164,000 (1)
Salem
 Salem Co., N.J.     Nuclear           1977-1981    164,000 (1)
Hope Creek
 Salem Co., N.J.     Nuclear           1987          52,000 (1)
Combustion Turbine
   Units             Oil/Gas           1967-1991    524,000
(various locations)

Diesel Units         Oil               1961-1970      8,700

Firm Capacity Purchases and Sales-Net               670,000 (2)

   Total Generating Capability                    2,348,700
                                                  ==========

Notes
(1) ACE's share of jointly-owned stations.  See Note 5 of ACE's
Notes to Financial Statements, incorporated by reference herein
as Exhibit 28(a).  (2) 125,000 KW from thirteen coal-fired units
of Pennsylvania Power & Light Company (PP&L), 579,000 KW from
four nonutility suppliers, and the sale of 34,000 KW to another
electric utility.

     Certain of ACE's units at the Deepwater and B. L. England
Stations and certain combustion turbine units have the capability
of using more than one primary fuel type.  In such instances, the
use of a particular fuel type depends upon relative cost,
availability and applicable environmental regulations and
requirements.  See Note 5 of the accompanying Notes to Financial
Statements for additional information regarding capital and
operating expenses of ACE's jointly-owned nuclear facilities.  

Power Pool and Interconnection Agreements

     ACE is a member of the Pennsylvania-New Jersey-Maryland
Interconnection Association (PJM), an integrated power pool which
coordinates the bulk power supply of eleven member utilities in
Pennsylvania, New Jersey, Delaware, Maryland, Virginia and the
District of Columbia, and is interconnected with other major
utilities in the northeastern United States.  As a member of PJM,
ACE is required to plan for reserve capacity based on estimated
aggregate PJM requirements allocated to member companies.  ACE
periodically files its capacity addition plans with PJM which are
intended to meet forecast capacity and reserve obligations.  PJM
member companies make use of a planning year concept in reviewing
capacity and reserve requirements.  Each planning year commences
on June 1 and ends on the succeeding May 31.  PJM provides for
after-the-fact accounting by its members for differences between
forecast and actual load experience.  ACE is also a party to the
Mid-Atlantic Area Coordination Agreement, which provides for
coordinated planning of generation and transmission facilities by
the companies included in PJM.  Further coordination of short
term power supply planning is provided by inter-area agreements
with adjacent power pools.  

     PJM currently operates on the basis of reliability of
service and operating economy.  To meet the goals outlined by
FERC in its open access NOPR, PJM has developed a comprehensive
proposal under which current members of PJM and other load-
serving entities will purchase regional "network" transmission
rights that are intended to enable them to reliably and
economically integrate generation and load.  Generators selling
power to serve pool load will not have to purchase transmission
service independently, which is intended to create a regional
wholesale power market.  In order to meet the requirements to
functionally unbundle transmission, PJM has proposed to
reorganize into an Independent System Operator (ISO) with
responsibility for operating the bulk power system, administering
the regional transmission service tariffs and managing the pool's
competitive energy market.  PJM will replace the existing system
of cost-based centralized dispatch with an expanded, hourly
bid/price pool in which all sellers will be able to bid their
energy into the pool and all load-serving entities will be able
to buy energy from the pool.  Further, under the proposal, PJM
will create new contractual mechanisms to ensure participation by
all entities responsible for serving load in decisions affecting
reliability.  Each load-serving entity that chooses to operate in
the PJM control area will be required to execute an agreement to
maintain adequate generation reserves and to share those reserves
on a reciprocal basis.   PJM will establish an enhanced regional
planning process, under the supervision of the ISO, to meet Mid-
Atlantic Area Reliability Council reliability requirements
applicable to both generation and transmission.  The PJM proposal
is subject to FERC approval and is expected to be filed with FERC
in 1996. 
  
Power Purchases and Sales

     ACE is currently purchasing 125 MW of capacity and energy
from PP&L coal-fired sources.  By letter dated March 16, 1995,
the Company notified PPL that this capacity and energy sales
agreement will be terminated effective March 1998.  To replace
the PPL arrangement, the Company has signed a letter of intent
with PECO Energy (PECO) for the purchase of 125 MWs for the
period beginning March 16, 1998 through May 31, 2000.  ACE also
has agreements with certain other electric utilities for the
purchase of short term generating capacity, energy and
transmission capacity on an as-needed basis, which are utilized
to the extent they are economic and available.  

     ACE has agreed to sell 34 MW of firm capacity to Baltimore
Gas & Electric Co. for the period June 1, 1995 through May 31,
1996.   

Capacity Planning

     New generating capacity built by a utility is subject to a
Certificate of Need (CON) process.  A CON is required prior to
constructing a new generating facility in excess of 100 MW, or
adding either 100 MW or 25% of capacity, whichever is smaller, to
an existing site.  In addition, New Jersey utilities are required
to comply with a stipulation of settlement approved by the BPU in
July 1988.  The purpose of the stipulation of settlement is to
procure future capacity and energy from qualified cogeneration
and small power production facilities through an annual
competitive bidding process, based on a long-term capacity plan. 
The amount to be bid upon is subject to BPU review and will be
based upon such factors as a utility's five year projected
capacity needs and its current generating capacity, service life
extension plans for existing units, new construction, power
purchases and commitments from other utilities and non-utility
sources.  In general, the procedures provide that each utility
will procure non-utility power when needed through an evaluation
system which ranks proposed projects on price and non-price
factors.  The price of such power is capped at the utility's
avoided cost, which avoided cost is subject to BPU review, with a
floor price of 25% of such avoided cost.  Non-price factors in
the evaluation process include project status and viability, fuel
source and efficiency, project location and environmental
effects.

     The stipulation of settlement referred to above was due to
expire on September 15, 1993.  The BPU ordered an extension of
the current filing requirements consistent with PURPA
requirements through February 18, 1995.  Similarly, the CON was
set to expire on January 30, 1994.  Since no processes were in
place to replace the CON, the New Jersey Department of
Environmental Protection (NJDEP) readopted the legislation and
extended it through January 28, 1999.  ACE, pursuant to the terms
of the July 1988 stipulation, filed data with the BPU in October
1995 covering the 15 year period from 1995 through 2009.  The
filing indicated that ACE did not require additional capacity
until 1999 when the need would be met with combined cycle units
and/or power purchases using the pre-described evaluation system. 
Subsequent updates to the load forecast and the recent
negotiations to purchase 175 MW of capacity and associated energy
from another utility commencing in 1999 delays the need for
additional capacity until the year 2000.
  
     ACE's ability to meet its planned capacity obligations and
its projected load growth will depend upon the continued
availability of currently owned and purchased generating
capability, on the availability of capacity from cogeneration and
other non-utility generating sources, on ACE's own planned
capacity additions and on capacity purchases from sources yet to
be determined.  ACE's installed capacity, planned capacity
additions, and capacity purchase arrangements for 1996-1998 are
expected to be sufficient to supply its share of PJM reserve
requirements during that period.  The on-going outage of the
Salem units has reduced ACE's installed generating capacity and
has required ACE to secure additional capacity, sufficient to
meet PJM reserve requirements.  Increases in PJM reserve
requirements and less than anticipated benefits associated with
conservation and load management efforts could further increase
ACE's need for additional generating capacity.  To the extent
that such capacity provided by others is not available, ACE would
be required to pursue other sources of capacity, and to
accelerate or expand its construction program which, in certain
instances, may require additional regulatory approvals and
construction expenditures which could be substantial.  On an
operational basis, ACE expects to be able to continue to meet the
demand for electricity on its system through operation of
available equipment and by power purchases.  However, if periods
of unusual demand should coincide with forced outages of
equipment, ACE could find it necessary at times to reduce or
curtail load in order to safeguard the continued operation of its
system.  See Note 10 of the accompanying Notes to Financial
Statements herein for additional information.  

Nonutility Generation

     Additional sources of capacity for use by ACE are made
available by non-utility sources, principally cogenerators.  ACE
currently has four, BPU-approved power purchase agreements for
the purchase of capacity and energy from non-utility sources
under the standard offer methodology developed and approved by
the BPU in August 1987.  

Project             Fuel           MW             Date of   
Location            Type         Provided    Commercial Operation

Chester,            solid
Pennsylvania        waste           75            September 1991
Pedricktown,
New Jersey          gas            116            March 1992
Carney's Point,
New Jersey          coal           188            March 1994
Logan Township,
New Jersey          coal           200            September 1994

     Total                         579 

     An amendment to the agreement between ACE and the sponsors
of the Pedricktown facility has restructured ACE's payment for
capacity and energy reducing the energy component of the payment. 
The amendment also increased the available capacity of the
facility from 106 MW to 116 MW and returns the project's thermal
host to ACE as a retail customer effective November 1995. 
Renegotiation of a third contract is currently underway and is
expected to be completed in the third quarter of 1996.  See Note
3 of the accompanying Notes to Financial Statements for
additional information regarding the recovery of capacity costs.  
  
<PAGE>
Nuclear Generating Station Developments

     ACE is a co-owner of the Hope Creek and Salem Nuclear
Generating Stations, to the extent of 5% and 7.41%, respectively. 
The Hope Creek Unit and Salem Units 1 and 2 are located adjacent
to each other in Salem County, New Jersey and are operated by PS. 
ACE is also an owner of 7.51% of Peach Bottom Units 2 and 3,
which are located in York County, Pennsylvania and are operated
by PECO.  See Note 5 of ACE's Notes to Financial Statements filed
as Exhibit 28(a) and incorporated by reference for additional
information relating to the Company's investment in jointly-owned
generating stations.  

          In 1995, nuclear generation provided 19% of ACE's total
energy output.  The approximate capacity factors (based on
maximum dependable capacity ratings) for ACE's jointly-owned
units for 1994 and 1995 were as follows:

   Unit                  1995                 1994               
Salem Unit 1             26.0%                59.3%               
Salem Unit 2             20.8%                57.8%              
Peach Bottom Unit 2      95.8%                80.3%       
Peach Bottom Unit 3      88.2%                97.8%              
Hope Creek               78.2%                78.9%               

See "Salem Station" below for additional information on operating
performance at Salem.

     ACE is collecting through rates amounts to fund its share of
estimated future costs relating to the decommissioning of the
five nuclear units in which it has joint ownership interests. 
Such estimated decommissioning costs are based on studies and
forecasts including generic estimates provided by the Nuclear
Regulatory Commission (NRC).  Funding to cover the future costs
of decommissioning each of the five nuclear units, as currently
authorized by the BPU and provided for in rates, is $6.4 million
annually.  Site specific studies are currently being performed
and expected to be completed during 1996.  At that time,
adjustments to funding amounts may be required.  

     See Notes 1 and 10 of the accompanying Notes to Financial
Statements for additional information relating to nuclear
decommissioning.

     ACE has been advised that the NRC has raised concerns that
the Thermo-Lag 330 fire barrier systems used to protect cables
and equipment at the Peach Bottom Station may not provide the
necessary level of fire protection and has requested licensees to
describe short and long term measures being taken to address this
concern.  ACE has been advised that PECO has informed the NRC
that it has taken short term compensatory actions to address the
inadequacies of the Thermo-Lag barriers installed at 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 PECO's interim actions
were acceptable.  PECO has advised ACE that PECO has been in
contact with the NRC regarding PECO's long term measures to
address Thermo-Lag fire barrier issues.  In 1995, PECO completed
its engineering re-analysis for Peach Bottom.  The re-analysis
identified proposed modifications to be performed over the next
several years in order to implement the long-term measures
addressing the concern over Thermo-Lag use.  NRC approval of the
proposed modifications is pending.  

     ACE has been advised that in October 1990 General Electric
Company (GE) reported that crack indications were discovered near
the seam welds in 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 BWR plants take
interim corrective actions, including a review of fabrication
records and visual examinations of accessible areas of the core
shroud seam welds.  Both Peach Bottom Units 2 and 3 and Hope
Creek are affected by this issue and both PECO and PS are
participating in the GE BWR Owners Group to evaluate this issue
and develop long term corrective action.  In June 1994, an
industry group was formed and subsequently established generic
inspection guidelines which were approved by the NRC.  PECO has
advised ACE that Peach Bottom 3 was last examined during its fall
1995 refueling outage and the extent of the cracking identified
was determined to be within industry-established guidelines.  In
a letter to the NRC dated November 3, 1995, PECO concluded that
there is a substantial margin for each core shroud weld to allow
for continued operation of Unit 3.  PECO has also advised ACE
that Peach Bottom 2 was examined in October 1994 during its
refueling outage.  Although some crack indications were
identified, PECO advised that they were considered to be much
less severe than those found on Unit 3 and no repairs were
required to operate Unit 2 for another two-year cycle.  At the
Hope Creek Unit, PS advised ACE that during the spring 1994
refueling outage, PS inspected the shroud of Hope Creek in
accordance with GE's recommendations and found no cracks.  PS
reports that due to the age and materials of the Hope Creek
shroud and the historical maintenance of low conductivity water
chemistry, Hope Creek has been placed in the lowest
susceptibility category under industry-established guidelines. 
Hope Creek must undergo another shroud inspection during its next
refueling outage in 1997, or install a preemptive repair that
would maintain the structural integrity of the shroud under all
normal and design basis accident conditions for the remaining
life of the plant.  ACE cannot predict what further action will
be taken with regard to these units or what long term corrective
actions, if any, will be identified.         
<PAGE>
     The periodic review and evaluation of nuclear generating
station licensees conducted by the NRC is known as the Systematic
Assessment of Licensee Performance (SALP).  Under the revised
SALP process, ratings are assigned in four assessment areas,
reduced from seven assessment areas:  Operations, Maintenance,
Engineering and Plant Support (the Plant Support area includes
security, emergency preparedness, radiological controls, fire
protection, chemistry and housekeeping).  Ratings are assigned
from "1" to "3", with "1" being the highest and "3" being the
lowest.

     As previously reported under Part 1, Item I-Business,
"Regulation" and Note 1 of the Notes to Financial Statements in
the Company's 1994 Annual Report on Form 10-K, New Jersey
Administrative Code 14:5A-2.1 requires that all New Jersey
electric utilities file with the BPU a nuclear decommissioning
cost update by January 1, 1996 and every four years thereafter. 
PS, on behalf of the co-owners of the Salem, Hope Creek and Peach
Bottom stations, has engaged an independent engineer to develop
this estimate.  ACE is a 7.41%, 5.00% and 7.51% owner of the
Salem, Hope Creek and Peach Bottom stations, respectively.  ACE
expects that its share of nuclear decommissioning cost will
increase, however, the magnitude of the increase cannot be
determined at this time.
<PAGE>
Salem Station 

     ACE is a 7.41% owner of Salem Nuclear Generating Station
(Salem) operated by PS.  Salem consists of two 1,100 MW
pressurized water nuclear reactors (PWR) representing 164,000 KW
of ACE's total installed capacity of 2,348,700 KW.  ACE's net
investment in the Salem Station was approximately $141.8 million,
or 6% of ACE's total assets at December 31, 1995. 

     ACE was advised on January 3, 1995, the NRC issued its SALP
report for the Salem Station for the period covering June 20,
1993 through November 5, 1994.  The Salem SALP report was issued
under the revised SALP process in which the number of assessment
areas has been reduced from seven to four:  Operations,
Maintenance, Engineering and Plant Support (the Plant Support
area includes security, emergency preparedness, radiological
controls, fire protection, chemistry and housekeeping).  The NRC
assigned ratings of "1" in the functional area of Plant Support,
"2" in the area of Engineering and "3" in the areas of Operations
and Maintenance.  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 has noted that although PS has
initiated several comprehensive actions within the past year to
improve plant performance, and some recent incremental gains have
been made, these efforts have yet to noticeably change overall
performance at Salem.

     ACE has been advised that on March 21, 1995, representatives
of the NRC staff met with the Boards of Directors of PS and PS'
parent company, Public Service Enterprise Group, to reiterate the
previously expressed concerns with regard to Salem's operations. 
The NRC staff acknowledged that PS had made efforts to improve
Salem's operations, including making senior management changes,
but indicated that demonstrated sustained results have not yet
been achieved.  

     ACE has been advised by PS that its own assessments, as well
as those by the NRC and the Institute of Nuclear Power
Operations, indicated that additional efforts are required to
further improve operating performance, as reflected in the
restart plans referred to above.  PS has advised ACE that PS is
committed to taking the necessary actions to address Salem's
performance needs.  It is anticipated that the NRC will continue
to maintain a close watch on Salem's restart activities and
subsequent operational performance.  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.  

     As previously reported, a Salem NRC enforcement conference
was held on July 28, 1995 related to certain violations of NRC
requirements at Salem.  The violations included valves that were
incorrectly positioned following a plant modification in May
1993, non-conservatisms in the setpoints for a pressurizer
overpressure protection system and several examples of inadequate
root cause determination of events, leading to insufficient
corrective actions at Salem.  On October 16, 1995, the NRC
proposed cumulative civil penalties of $600,000 related to these
violations.  PS has advised the NRC that the proposed penalties
would not be contested.

     ACE has been advised that on October 5, 1995, PS declared an
alert at Salem Unit 1.  The event involved a problem with the
overhead annunciator panel in the Unit 1 control room. PS has
chartered a significant event response team (SERT) to investigate
the event, determine the root causes and suggest corrective
actions.  Simultaneously, the NRC formed a special inspection
team to investigate the event during the period October 6 through
October 18.  What actions the NRC might take, if any, cannot be
determined at this time.  At the time of the event there was no
fuel in the reactor, no release of radiation and no danger to the
public or on-site personnel.

     Salem 1 and 2 have been out of service since May 16, 1995
and June 7, 1995, respectively.  ACE has been advised that since
that time, PS has been engaged in a thorough assessment of each
unit to identify and complete the work necessary to achieve safe,
sustained, reliable and economic operation.  PS 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 PS.  

     ACE was advised that on December 11, 1995, PS 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 PS indicating
that it had concluded that PS's overall restart plan, if
implemented effectively, should adequately address the numerous
Salem issues to support a safe plant restart, and describing
further actions the NRC will undertake to confirm that PS'
actions have resulted in the necessary performance improvements
to support safe plant restart.  

     As a part of PS' comprehensive review, ACE has been advised
that an extensive 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 PWR's 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 pressurized water reactors.  This generic
letter requested utilities with pressurized water reactors to
conduct steam generator examinations with more sensitive
inspection devices capable of detecting evidence of degradation. 
Subsequently, PS 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 I, ACE has been advised that the most
recent inspection of the steam generators is not complete, but
partial results from eddy current inspections in February 1996
using this new technology show indications of degradation in a
significant number of tubes.  The inspections are continuing and
PS has decided to remove several tubes for laboratory examination
to confirm the results of the inspections.  Removal of the tubes
should be completed in March and preliminary results of the state
of the Salem 1 tubes from the subsequent laboratory examinations
should be known in April.  However, based on the results of
inspections to date, PS has concluded that the Salem 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 an 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 1 tubes are fully
examined, PS will be able to evaluate its course of action in
light of NRC and other industry requirements.  

     ACE has been advised that the examination of the Salem 2
steam generators was completed in January 1996 using the same
testing device used in Salem 1.  The results of the Salem 2
inspection are being reviewed again to confirm their results in
light of the experience with Salem 1.  Although this review has
not yet been completed, results to date appear to confirm that
the condition of the Salem 2 steam generators is well within
current repair limits at the present time.  PS will also remove
tubes from the Salem 2 steam generators for laboratory analysis
to further confirm the results of this testing. 

     ACE has been advised that PS had planned to return Salem 1
to service in the second quarter of 1996 and Salem 2 in the third
quarter of 1996.  As a result of the extent of the recently
discovered degradation in the Salem 1 steam generators, PS is
focusing its efforts on the return of Salem 2 to service in the
third quarter.  The additional steam generator inspections and
testing on Salem 2 is not expected to adversely affect the timing
of its restart.  However, the timing of the restart is subject to
completion of the requirements of the restart plan to the
satisfaction of PS and the NRC as well as to the normal
uncertainties associated with such a substantial review and
improvement of the systems of a large nuclear unit, so that no
assurance can be given that the projected return date will be
met.  

     ACE's share of additional operating and maintenance expenses
associated with Salem restart activities in 1995 was $2.6
million.  In 1996 operations and maintenance expenses are
estimated to be $5.8 million and capital expenditures to amount
to $1.9 million.  ACE's share of total operating and maintenance
expenses for both Salem units for the year was $24.5 million and
capital costs were $10.6 million.  For 1996, ACE does not
presently expect its share of operating and maintenance expenses
or capital costs for Salem Station to exceed 1995 amounts;
however this could change as a result of the steam generator
inspection results referred to above.  

     The outage of each Salem unit causes ACE to incur
replacement power costs of approximately $700 thousand per month
per unit.  Such amounts vary, however, depending on the
availability of other generation, the cost of purchased energy
and other factors, including modifications to maintenance
schedules of other units.  Based on the information provided by
PS regarding the delay in the return of Salem Unit 1, the return
of Salem Unit 2 in the third quarter of 1996 and expected
operation of the other nuclear units in which ACE has an
ownership interest, ACE presently estimates that its aggregate
nuclear capacity factor for 1996 will be approximately 50%.  Such
capacity factor would result in an estimated penalty of $3.3
million under the BPU nuclear performance standard.   

     On February 27, 1996, the Salem co-owners filed a Complaint
in United States District Court for the District of New Jersey
against Westinghouse Electric Corporation, the designer and
manufacturer of the Salem steam generators, under state and
federal RICO statutes alleging fraud, negligent misrepresentation
and breach of contract.  The Westinghouse complaint seeks
compensatory and punitive damages.      

     On March 5, 1996, ACE filed a Complaint in Superior Court of
New Jersey against PS seeking compensatory damages based on
allegations of breach of contract and negligence.  ACE has been
advised that the other nonoperating co-owners of Salem have filed
a similar complaint against PS in the United States District
Court for the Eastern District of Pennsylvania.

     ACE was advised in 1990 that the NJDEP issued a draft New
Jersey Pollutant Discharge Elimination System (NJPDES) Permit to
the Salem Station which required closed-cycle cooling.  In
response to the 1990 Draft Permit, PS submitted further written
comments to the NJDEP regarding the ecological effects of station
operations demonstrating that Salem was not having and would not
have an adverse environmental impact and that closed-cycle
cooling was an inappropriate solution.  PS also developed and
submitted a supplement to the permit renewal application setting
forth an alternative approach that would protect aquatic life in
the Delaware Estuary and provide other ecological benefits.  PS
proposed intake screen modifications to reduce fish loss, a study
of sound deterrent systems to divert fish from the intake and a
limit on intake flow.  In addition, PS proposed conservation
measures, including the restoration of up to 10,000 acres of
degraded wetlands and the installation of fish ladders to allow
fish to reach upstream spawning areas.  Finally, PS proposed a
comprehensive biological monitoring program to expand existing
knowledge of the Delaware Estuary and to monitor station impacts. 
In June 1993, ACE was advised that the NJDEP issued Salem a
revised draft permit which reconsidered the requirement for
closed-cycle cooling and adopted the alternative measures
proposed by PS with certain modifications.  A final five-year
permit was issued on July 20, 1994 with an effective date of
September 1, 1994.  The Environmental Protection Agency (EPA),
which has the authority to review the final permit issued by the
NJDEP, completed its review and has not raised any objections. 
Certain environmental groups and other entities, including the
State of Delaware, have filed requests for hearings with the
NJDEP challenging the final permit.  The NJDEP granted the
hearing requests on certain of the issues and PS has been named
as a respondent along with the NJDEP in these matters which are
pending in the Office of Administrative Law of the State of New
Jersey.  ACE has been advised that PS is implementing the final
permit.  Additional permits from various agencies must be
obtained to implement the permit.  No assurances can be given as
to receipt of any such additional permits.  PS has advised ACE
that it estimates that the cost of compliance with the final
permit is approximately $100 million, of which ACE's share is
7.41% and is included in ACE's current forecast of construction
expenditures.

     On March 13, 1996, the BPU announced that all revenues
associated with Salem Unit 1 would be made interim and subject to
refund effective immediately, pending further investigation and
hearings on the steam generator cracking and the expected return
date of the unit.  The BPU also announced that ACE must
demonstrate why revenues for Salem Unit 2 should not be made
interim and subject to refund.  For further information with
regard to this and other rate issues, see "Rates" herein. 
  
     At this time, it is not possible to predict what other
actions may be taken in any regulatory, administrative or civil
proceedings by ACE or others, the outcome of any such
proceedings, if commenced, or the ultimate amount of
responsibility of ACE for costs and penalties arising from such
proceedings. 

Hope Creek Station

     ACE is a 5% owner of Hope Creek Nuclear Generating Station
(Hope Creek) which is operated by PS.  An outage of the Hope
Creek unit can cause ACE to incur replacement power costs
currently estimated to be $400 thousand per month, depending on
the availability of other generation, the cost of purchased
energy and other factor including changes in maintenance
schedules of other units. 

     Hope Creek is currently undergoing a refueling and
maintenance outage which commenced November 11, 1995.

     The NRC's most recent SALP report for Hope Creek for the
period June 20 1993 through April 22, 1995 assigned ratings of
"1" in the area of Plant Support and a rating of "2" in the
functional category of Engineering, Operations and Maintenance.
The NRC noted an overall decline in performance in the
Operations, Maintenance and Engineering areas compared to the
previous SALP period, and cited weak root cause analysis as a
dominant factor.

     ACE has been advised by PS that as a result of an internal
allegation report, PS submitted a Licensee Event Report in
October 1994 which stated that the Hope Creek control room was
understaffed for approximately three minutes and a decision was
made by those involved that the incident did not warrant
initiation of NRC reporting documentation.  PS has advised ACE
that a meeting with NRC Region I personnel was held on October
18, 1994 in which the NRC expressed a high degree of concern over
the issue.  After investigation by both the NRC and PS, on
September 19, 1995, the NRC issued two Level IV violations with
no civil penalty.

     PS has advised ACE that a small amount of low-level
radioactive material was released to the atmosphere at Hope Creek
on April 5, 1995.  PS advised that the release did not exceed
federal limits nor pose any danger to the public or plant
employees; however, a trailer driven offsite had exceeded the
limit for releasing materials and was later cleaned.  PS and the
NRC have investigated the event, and on June 16, 1995 an
enforcement conference was held.  On July 20, 1995, the NRC
issued a Notice of Violation for the Hope Creek unplanned release
which noted four violations.  No fine was issued, partly because
of the comprehensive corrective actions taken following the event
and the plant's history of limited enforcement action.  

<PAGE>
     ACE has been advised that on July 8, 1995, during a manual
shutdown of Hope Creek for repair of control room ventilation
equipment, operators partially opened a valve for a period of
time and reduced the effectiveness of the shutdown cooling
system.  Although the impact of the event to plant safety was
minimal, the positioning of the valve and the resulting
temperature change violated plant procedures and technical
specifications.  On July 31, 1995, NRC staff met with plant
management concerning this issue and subsequently decided to
assign a special inspection team to independently evaluate this
event as well as PS' response to it, including PS' procedures and
training for operator handling of abnormal conditions.  ACE was
advised that on September 25, 1995, the NRC's special inspection
team issued its report and identified several areas where
operator and senior plant management performance during this
event was inadequate.  PS has advised ACE that an NRC enforcement
conference was held on November 6, 1995, and on December 12,
1995, the NRC issued a Level III violation for this event with a
civil penalty of $100,000.  
     
     As previously reported, PS had advised ACE that the NRC, by
letter dated December 1, 1995, informed PS that a Plant
Performance Review performed by the NRC for the period April
23,1995 to October 21, 1995 indicated a continued decline in
plant performance, and that PS had determined to extend the
refueling outage to include the implementation of corrective
actions to eliminate operational deficiencies noted by the NRC
and detected by PS through self assessment.  PS has also advised
ACE that in the NRC December 1, 1995, letter the NRC requested a
management meeting prior to restart to allow PS to present its
self assessment of the progress made during the outage and of the
readiness of the unit for restart.  ACE has also been advised
that on February 12, 1996 the NRC commenced a Readiness
Assessment Team Inspection for Hope Creek, scheduled to be
completed on March 1, 1996, and that the Hope Creek unit is
expected to return to service in March 1996.  It is not possible
to predict the outcome of the NRC inspection or what other
actions which may be taken by the NRC with respect
to Hope Creek. 

     ACE has been advised that by letter dated January 29, 1996,
the NRC requested a meeting with PS senior management to discuss
its concerns regarding declining trends in performance at Hope
Creek.  The meeting has not yet been scheduled but is expected to
occur after the restart of Hope Creek from its current refueling
and maintenance outage. 
<PAGE>
Peach Bottom Station

     ACE is a 7.51% owner of Peach Bottom Atomic Power Station
(Peach Bottom) operated by PECO.

     ACE has been advised that on January 19, 1996, the NRC
issued its SALP report for the Peach Bottom Station for the
period covering May 1, 1994 through October 14, 1995.  The NRC
assigned ratings of "1" in the functional areas of Plant
Operations, Maintenance and Plant Support.  Engineering received
a rating of "2".  The NRC found continued improvement in
performance during the period.  Operator performance continued to
be a strength, as well as operations management oversight.
Effective engineering management actions to improve the overall
self assessment and system performance were noted, as well as
good management oversight activities.  Response to emerging
issues, equipment problems and event related issues were noted as
particularly strong. However, lapses in the quality of technical
work and in modification implementation indicated inconsistent
performance, and resulted in a repeat rating of "2" for the
Engineering area.  ACE has been advised that PECO will be taking
actions to address weaknesses discussed in the SALP Report.    

     As previously reported in the June 30, 1995 report on Form
10-Q, ACE has been advised by PECO that on August 2, 1995, the
NRC held an predecisional enforcement conference regarding three
alleged violations in control and design activities and technical
specification requirements regarding operability of the emergency
diesel generators. ACE has been advised that on August 17, 1995,
the NRC issued its notice of violation report and, in the report,
recognized that PECO identified the problem issues, conducted a
detailed root cause evaluation and took appropriate corrective
actions.  The NRC elected not to propose a civil penalty in this
case based on the identification and corrective action taken by
PECO.

     ACE has been advised by PECO that, by letter dated October
18, 1994, the NRC has approved PECO's request to rerate the
authorized maximum reactor core power levels of Peach Bottom
Units No. 2 and 3 by 5% to 3,458 MWs from the current limits of
3,293 MWs.  The amendment of the Peach Bottom Unit No. 2 facility
operating license was effective upon the date of the NRC approval
letter.  The amendment of the Unit No. 3 facility operating
license became effective with the completion of hardware changes
which were done during Unit No. 3's fall 1995 refueling outage.

<PAGE>
Fuel Supply

     ACE's sources of electrical energy (including power
purchases) for the years indicated are shown below:

Source                        1995       1994          1993     
Coal                           33%         29%          34%  
Nuclear                        19%         23%          24%  
Oil/Natural Gas                 3%          7%           5%       
Interchange and
 Purchased Power               21%         24%          28%  
Nonutility                     24%         17%           9%       
         
     The prices of all types of fuels used by ACE for the
generation of electricity are subject to various factors, such as
world markets, labor unrest and actions by governmental
authorities, including allocations of fuel supplies, over which
ACE has no control.

     Oil

     Residual oil and distillate oil for ACE's wholly-owned
stations are furnished under two separate contracts with a major
fuel supplier.  ACE has a contract for the supply of 1.0% sulfur
residual oil for both Deepwater and B. L. England Stations and
for distillate oil sufficient to supply ACE's combustion
turbines.  Both contracts expire October 31, 1997.  See
"Environmental Controls-Air" for information concerning the use
of particular fuels at B. L. England Station.  

     On December 31, 1995, the oil supply at Deepwater Station
was sufficient to operate Deepwater Unit 1 for 45 days, and the
supply at B. L. England Station was sufficient to operate Unit 3
for 45 days. 

     Coal

     ACE has contracted with one supplier for the purchase of
2.6% sulfur coal for B. L. England Units 1 and 2 through April
30, 1999.  On December 31, 1995, the coal inventory at the B. L.
England Station was sufficient to operate Units 1 and 2 for 30
days.  See "Environmental Controls-Air" herein for additional
information relating to B.L. England Station. 

     ACE has contracted with one supplier for the purchase of
1.0% sulfur coal for Deepwater Unit 6/8 through June 30, 1998. 
On December 31, 1995, the coal inventory at Deepwater Station was
sufficient to operate Unit 6/8 for 92 days.

     The Keystone and Conemaugh Stations, in which ACE has joint
ownership interests of 2.47% and 3.83%, respectively, are mine-
mouth generating stations located in western Pennsylvania.  The
owners of the Keystone Station have a contract through 2004,
providing for a portion of the annual bituminous coal
requirements of the Keystone Station.  A combination of long and
short term contracts provide for the annual bituminous coal
requirements of the Conemaugh Station.  To the extent that the
requirements of both plants are not covered by these contracts,
coal supplies are obtained from local suppliers.  As of December
31, 1995, Keystone and Conemaugh had approximately a 41 day
supply and a 44 day supply of coal, respectively.

     Gas 

     ACE is currently capable of firing natural gas in six
combustion turbine peaking units and in two conventional steam
turbine generating units.  ACE has entered into a firm electric
service tariff with the local distribution company for the supply
of natural gas to its units.  The tariff provides for the payment
of certain commodity and demand charges.  Portions of the gas
supply are obtained from the spot market under short term
renewable gas supply and transportation contracts with various
producers/suppliers and pipelines.

Nuclear Fuel

     As a joint owner of the Peach Bottom, Salem and Hope Creek
generating units, ACE relies upon the respective operating
company for arrangements for nuclear fuel supply and management.
ACE is responsible for the costs thereof to the extent of its
particular ownership interest through an arrangement with a third
party.  Generally, the supply of fuel for nuclear generating
units involves the mining and milling of uranium ore to uranium
concentrate, conversion of the uranium concentrate to uranium
hexafluoride, enrichment of uranium hexafluoride and fabrication
of fuel assemblies.  After spent fuel is removed from a nuclear
reactor, it is placed in temporary storage for cooling in a spent
fuel pool at the nuclear station site.  Under the Nuclear Waste
Policy Act of 1982 (NWPA), the Federal government has a
contractual obligation for transportation and ultimate disposal
of the spent fuel.  See Note 12 of the accompanying Notes to
Financial Statements for financing arrangements for nuclear fuel.

     ACE has been advised by PECO, the operator of Peach Bottom,
that it has contracts for uranium concentrates to fully operate
Peach Bottom Units 2 and 3 through 2002.  On February 25, 1995,
two companies which supply uranium concentrates to PECO filed
petitions for bankruptcy protection under Chapter 11 of the
Bankruptcy Code.  The two companies supply approximately half of
PECO's 1995 and 1996 requirements for uranium concentrates.  In
addition, one of the companies is under contract to supply
approximately 25% of PECO's uranium concentrate requirements for
the period 1997 to 2002.  PECO has made alternate arrangements
with other suppliers to satisfy its short-term requirements for
uranium concentrates.  PECO is also finalizing arrangements with
another supplier to satisfy PECO's longer-term needs.  ACE has
been advised that PECO does not anticipate any difficulties in
obtaining its requirements for uranium concentrates.  ACE has
also been advised by PECO that its contracts for uranium
concentrates will be allocated to the Peach Bottom units, and
other PECO nuclear facilities in which ACE has no ownership
interest, on an as-needed basis.  

     ACE has also been advised that PECO has contracted for the
following segments of the nuclear fuel supply cycle with respect
to the Peach Bottom units through the following years:

Nuclear Unit         Conversion     Enrichment       Fabrication

Peach Bottom Unit 2      1997         1998              1999
Peach Bottom Unit 3      1997         1998              1998

     ACE has been advised by PS, the operating company for the
Salem and Hope Creek Stations, that it has arrangements which are
expected to provide sufficient uranium concentrates to meet the
current projected requirements of the Salem and Hope Creek units
through the year 2000 and approximately 60% of the requirements
through 2002.  PS has advised ACE that present contracts meet the
other nuclear fuel cycle requirements for the Salem and Hope
Creek units through the years indicated below:

Nuclear Unit         Conversion     Enrichment       Fabrication

  Salem Unit 1          2000           (1)             2004
  Salem Unit 2          2000           (1)             2005
  Hope Creek            2000           (1)             2000

(1) 100% coverage through 1998, approximately 50% through 2002;
and approximately 30% through 2004.  PS has advised ACE that it
does not anticipate difficulties in obtaining necessary
enrichment service for the Salem and Hope Creek units.

     In conformity with the NWPA, PS and PECO, on behalf of the
co-owners of the Salem and Hope Creek, and Peach Bottom stations,
respectively, have entered into contracts with the U.S.
Department of Energy (DOE) for the disposal of spent nuclear fuel
from those stations.  Under these contracts, the DOE is to take
title to the spent fuel at the site, then transport it and
provide for its permanent disposal at a cost to utilities based
on nuclear generation, subject to such escalation as may be
required to assure full cost recovery by the Federal government. 

     Under NWPA, the Federal government must commence the
acceptance of these materials for permanent offsite storage no
later than 1998, but it is possible that such storage may be
delayed indefinitely.  ACE has been advised that the DOE has
stated that it would not be able to open a permanent, high-level
nuclear waste storage facility until 2015, at the earliest. 
Legislation has been introduced in Congress for the construction
of a temporary storage facility which would accept spent nuclear
fuel from utilities in 1998 or soon thereafter.  ACE has been
advised that the NRC has determined that spent nuclear fuel
generated in any reactor can be stored safely and without
significant environmental impacts in reactor facility storage
pools or in independent spent fuel storage installations located
at reactor or away-from-reactor sites for at least 30 years
beyond the licensed life for operation (which may include the
term of a revised or renewed license).  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.  It is not possible for ACE to predict when any type of
Federal storage facility will become available, or what offsets
to the costs of storage, if any, will be available.

     PECO has advised ACE that spent fuel racks at Peach Bottom
Units 2 and 3 have storage capacity until 1998 for Unit 2 and
1999 for Unit 3.  Options for expansion of storage capacity at
Peach Bottom beyond the pertinent dates, including rod
consolidation, are being investigated.    

     PS has advised ACE that as a result of reracking two spent
fuel pools at Salem, the availability of adequate spent fuel
storage capacity is conservatively estimated through 2008 for
Salem 1 and 2012 for Salem 2, prior to losing an operational full
core discharge reserve.  The Hope Creek pool is also fully racked
and it is conservatively expected to provide storage capacity
until 2006, again prior to losing an operational full core
discharge reserve.  The units can be safely operated for many
years beyond these dates, as pool storage capacity will continue
to be available.  These dates assist in planning the need for
additional storage capacity that may be needed to operate the
units until the expiration of their operating license.  

Nuclear Decommissioning

     See Note 10-Nuclear Plant Decommissioning and Other of the
accompanying Notes to Financial Statements for information
relating to decommissioning of the five nuclear units in which
ACE has an ownership interest.  

     The Energy Policy Act states, among other things, that
utilities with nuclear reactors must pay for the decommissioning
and decontamination of the DOE nuclear fuel enrichment
facilities.  The total costs are estimated to be $150 million per
year for 15 years, of which ACE's share is estimated to be $8.5
million.  The Act provides that these costs are to be recoverable
in the same manner as other fuel costs.  ACE has recorded a 
liability of $6 million and a related regulatory asset of $6.4
million for such costs at December 31, 1995.  ACE made its first
payment related to this liability to the respective operating
companies in September 1993 and continues to make payments as
required.  In ACE's 1993 LEC filing, the BPU approved a
stipulation of settlement which included, among other things, the
full LEC recovery of this and future assessments.

     In January 1993, the BPU adopted N.J.A.C. 14:5A which was
designed to provide a mechanism for periodic review of the
estimated costs of decommissioning nuclear generating stations
owned by New Jersey electric utilities.  The purpose of this
regulation is to insure that adequate funds are available to
assure completion of decommissioning activities at the cessation
of commercial operation.  The regulation established
decommissioning trust fund reporting requirements for electric
utilities in order to provide the BPU with timely information for
its oversight of these funds.  

     On January 3, 1996, PS and ACE jointly filed with the BPU
its 1995 Nuclear Decommissioning Cost updates pursuant to
N.J.A.C. 14:5A-2 et seq.  In order to comply with N.J.A.C. 14:5A-
2.2(a)2, PS and ACE jointly filed NRC cost estimates for each of
their five jointly owned nuclear units.  These cost estimates are
based on the NRC's existing generic formula.  ACE and PS do not
believe that these NRC generic estimates provide an accurate
estimate of the cost of decommissioning the nuclear units. 
Inclusion of these NRC generic estimates should not be
interpreted as a validation by ACE and PS of the appropriateness
of these estimates for estimating the cost of decommissioning the
nuclear units.  ACE and PS believe these costs are best estimated
with periodic site-specific studies.  Such site-specific studies
are currently being undertaken and upon completion will be filed
with the BPU later in 1996.   
     
Regulation

     ACE is a public utility organized under the laws of New
Jersey and is subject to regulation as such by the BPU, among
others, which is also charged with the responsibility for energy
planning and coordination within the State of New Jersey.  ACE is
also subject to regulation by the Pennsylvania Public Utility
Commission in limited respects concerning property and operations
in Pennsylvania.  ACE is also subject, in certain respects, to
the jurisdiction of the FERC, and ACE maintains a system of
accounts in conformity with the Uniform System of Accounts
prescribed for public utilities and licensees subject to the
provisions of the Federal Power Act.

     The construction of generating stations and the availability
of generating units for commercial operation are subject to the
receipt of necessary authorizations and permits from regulatory
agencies and governmental bodies.  Standards as to environmental
suitability or operating safety are subject to change. 
Litigation or legislation designed to delay or prevent
construction of generating facilities and to limit the use of
existing facilities may adversely affect the planned installation
and operation of such facilities.  No assurance can be given that
necessary authorizations and permits will be received or
continued in effect, or that standards as to environmental
suitability or operating safety will not be changed in a manner
to adversely affect the Company, ACE or its operations.

     Pursuant to legislation enacted in the State of New Jersey
in 1983, no public utility can commence construction of certain
electric facilities without having obtained a certificate of need
from the appropriate state regulatory authorities.  For purposes
of the legislation, such electrical facilities are electric
generating units at a single site having a combined capacity of
100 MW or more and electric generating units which, when added to
an existing electric generating facility, would increase the
installed capacity of such facility by 25% or by more than 100
MW, whichever is smaller. 

     Operation of nuclear generating units involves continuous
close regulation by the NRC.  Such regulation involves testing,
evaluation and modification of all aspects of plant operation in
light of NRC safety and environmental requirements, and
continuous demonstration to the NRC that plant operations meet
applicable requirements.  The NRC has the ultimate authority to
determine whether any nuclear generating plant may operate.  In
addition, the Federal Emergency Management Agency has
responsibility for the review, in conjunction with the NRC, of
certain aspects of emergency planning relating to the operation
of nuclear plants.

     As a by-product of nuclear operations, nuclear generating
units, including those in which ACE owns an interest, produce
substantial amounts of low-level radioactive waste (LLRW).  Such
waste is presently accumulated on-site pending permanent storage
in federally licensed disposal facilities located elsewhere.  The
Federal Low Level Radioactive Policy Act, as amended (LLRWPA),
provides that each state must have a permanent storage faciity
operational by January 1, 1996.  ACE has been advised that to
date Pennsylvania has met such requirements by entering into a
compact with West Virginia, Maryland, Delaware and the District
of Columbia.  To date, New Jersey has complied with the LLRWPA
requirements by entering into a compact with the State of
Connecticut and certifying its capability to manage, store or
dispose of low-level radioactive waste requiring disposal after
December 31, 1992.  ACE has been advised by PS and PECO that LLRW
generated at Salem, Hope Creek and Peach Bottom is being
temporarily stored in on-site facilities pending development of
permanent disposal sites in New Jersey and Pennsylvania.  PS's
on-site facility, completed in September 1994, provides storage
for 5 years from Hope Creek and Salem.  It will be used for
interim storage of radioactive materials and waste, and if it
proves necessary in the future, to temporarily store waste until
New Jersey provides a permanent disposal facility.  PECO has
advised that is has an on-site LLRW storage facility for Peach
Bottom which will also provide at least 5 years of temporary
storage.  PECO has also advised that Pennsylvania is pursuing its
own LLRW site development via state-selected candidate sites,
along with a volunteer plan option.  New Jersey has introduced a
volunteer siting process to establish a LLRW disposal facility by
the year 2000.  Public meetings have been held across the state
in an effort to provide information to and obtain feedback from
the public.  To date, there have been no volunteers identified.
In June 1991, New Jersey enacted legislation providing for
funding of an estimated $90 million cost of establishing a
facility for disposal by 1998.  Fee regulation provided for in
the statute will permit the state to recover costs of such
facility from waste generators. 

     In March 1983, New Jersey enacted the Public Utility Fault
Determination Act which requires that the BPU make a
determination of fault with regard to any past or future accident
at any electric generating or transmission facility, prior to
granting a request by that utility for a rate increase to cover
accident-related costs in excess of $10 million.  However, the
law allows the affected utility to file for non-accident related
rate increases during such fault determination hearings and to
recover contributions to federally mandated or voluntary cost-
sharing plans.  The law further allows the BPU to authorize the
recovery of certain fault-related repair, cleanup, power
replacement or damage costs if substantiated by the evidence
presented and if authorized in writing by the BPU.

     In April 1995, Atlantic Jersey Thermal Systems, Inc. (AJTS),
a wholly-owned subsidiary of ATS, filed a petition with the BPU
for an order declaring that AJTS not be deemed a "public utility"
under New Jersey law subject to the BPU's jurisdiction by reason
of either its ownership and operation of a proposed thermal
energy production facility serving certain customers in Atlantic
City or the sale of thermal energy therefrom.  AJTS has proposed
that its thermal energy services would not constitute the
operation of facilities for public use, but will service a
limited number of large, sophisticated energy consumers through
individually-negotiated service agreements.  The BPU has not yet
issued a ruling and the final outcome cannot be determined at
this time.   

     Information regarding ACE's nuclear power replacement cost
insurance and liability under the Federal Price-Anderson Act is
incorporated herein by reference to Note 8 of ACE's Notes to
Financial Statements, filed as Exhibit 28(a) to this report.
<PAGE>
Environmental Matters

     General

     ACE is subject to regulation with respect to air and water
quality and other environmental matters by various Federal, state
and local authorities.  Emissions and discharges from ACE's
facilities are required to meet established criteria, and
numerous permits are required to construct new facilities and to
operate new and existing facilities.  Additional regulations and
requirements are continually being developed by various
government agencies.  The principal laws, regulations and
agencies relating to the protection of the environment which
affect ACE's operations are described below.

     Construction projects and operations of ACE are affected by
the National Environmental Policy Act under which all Federal
agencies are required to give appropriate consideration to
environmental values in major Federal actions significantly
affecting the quality of the human environment.

     The Federal Resource Conservation and Recovery Act of 1976
(RCRA) provides for the identification of hazardous waste and
includes standards and procedures that must be followed by all
persons that generate, transport, treat, store or dispose of
hazardous waste.  ACE has filed notifications and plans with the
U. S. EPA relating to the generation and treatment of hazardous
waste at certain of its facilities and generating stations.

     The Federal Comprehensive Environmental Response,
Compensation and Liability Act of 1980 (CERCLA), as amended by
the Superfund Amendments and Reauthorization Act of 1986 (SARA),
and RCRA authorize the EPA to bring an enforcement action to
compel responsible parties to take investigative and/or cleanup
actions at any site that is determined to present an imminent and
substantial danger to the public or to the environment because of
an actual or threatened release of one or more hazardous
substances. The New Jersey Spill Compensation and Control Act
(Spill Act) provides similar authority to the NJDEP.  Because of
the nature of ACE's business, including the production of
electricity, various by-products and substances are produced
and/or handled which are classified as hazardous under the above
laws. ACE generally provides for the disposal and/or processing
of such substances through licensed independent contractors.
However, the statutory provisions may impose joint and several
responsibility without regard to fault on the generators of
hazardous substances for certain investigative and/or cleanup
costs at the site where these substances were disposed and/or
processed. Generally, actions directed at funding such site
investigations and/or cleanups include all known allegedly
responsible parties.

     ACE has received requests for information under CERCLA with
respect to certain sites.  One site, a sanitary landfill
comprising approximately 40 acres, is situated in Atlantic
County, New Jersey.  ACE received a Directive, dated November 7,
1991, from the NJDEP, identifying ACE as one of a number of
parties allegedly responsible for the placement of certain
hazardous substances, namely, flyash which had been approved as
landfill material.  An Administrative Consent Order (ACO) has
been executed and submitted to the NJDEP by ACE and at least four
other identified responsible parties.  Site remediation will
include a soil cover of the site.  ACE has joined with three
other parties and will cooperate in implementing the terms of the
ACO.  Approximately eight additional responsible parties have
also been identified by the NJDEP.  ACE, together with the other
signatories to the ACO, will pursue recovery against those
persons who may also pursue recovery against other responsible
parties not named in the NJDEP Directive.  

     ACE has been served a Summons and Complaint dated June 30,
1992 in a civil action brought pursuant to Section 107(a) of
CERCLA on behalf of the EPA.  ACE has been named as one of
several defendants in connection with the recovery of costs
incurred, and to be incurred, in response to the alleged release
of hazardous substances located in Gloucester County, New Jersey. 
Approximately 70 separate financially solvent entities have been
identified as having responsibility for remediation which is now
predicted to be in excess of $175 million.  Sufficient discovery
has been conducted to establish that ACE's contribution to the
clean-up and remediation activity will be within the lower tiers
of financial participation.  Notwithstanding the joint and
several liability imposed by law, primary responsibility will be
apportioned among others, including Federal and state agencies
and private parties.  It is estimated that ACE's contribution for
the remediation and clean-up of both the Atlantic County and
Gloucester County sites is not expected to exceed $1 million.  

     The New Jersey Environmental Clean-up Responsibility Act was
supplemented and amended in June 1993 and became the New Jersey
Industrial Site Recovery Act.  The act provides, among other
things, that any business having certain Standard Industrial
Classification Code numbers that generates, uses, transports,
manufactures, refines, treats, stores, handles or disposes of
hazardous substances or hazardous wastes is subject to the
requirements of the act upon the closing of operations or a
transfer of ownership or operations.  As a precondition to such
termination or transfer of ownership or operations, the approval
of the NJDEP of a negative declaration, a remedial action work
plan or a remediation agreement and the establishment of the
remediation funding source is required.   
     
     Various state and Federal legislation have established a
comprehensive program for the disclosure of information about
hazardous substances in the workplace and the community, and
provided a procedure whereby workers and residents can gain
access to this information.  Implementing the regulations
provides for extensive recordkeeping, labeling and training to be
accomplished by each employer responsible for the handling of
hazardous substances.  ACE has implemented the requirements of
this legislation to achieve substantial compliance with
appropriate schedules.

     ACE is also subject to the Wetlands Act of 1970, which
requires applications to and permits from the NJDEP for
conducting regulated activities (including construction and
excavation) within the "coastal wetlands," as defined therein. 
Legislation enacted in 1987 by the State of New Jersey designates
certain areas as fresh water wetlands and restricts development
in those areas.  

     The New Jersey Coastal Area Facility Review Act (CAFRA)
requires applications to and permits from the NJDEP for
construction of certain types of facilities within the "coastal
area" as defined by CAFRA.  Recent changes in regulations
effective July 1994 may have substantive impact and are in the
process of being finalized.  Although the CAFRA regulations, as
initially drafted, exclude certain utilities from the most
rigorous portions of the regulations, electric utilities were not
excluded.  At the present time, the NJDEP indicates that the
final rules will exclude electric lines and substation
construction and maintenance from the definition of "public
development".  These activities will then be excluded from
regulation.  The regulations do not effect existing facilities or
equipment and ACE does not presently have construction of such
facilities or equipment planned.  ACE will continue pursuit for
the exemption.      

     Public concern continues over the health effects from
exposure to electric and magnetic fields (EMF).  To date, there
are not conclusive scientific studies to support such concerns. 
The New Jersey Commission on Radiation Protection (CORP) is
considering promulgation of regulations which would authorize the
NJDEP to review all new power line projects of 100 kilovolts or
more.  While the promulgation of such regulations may affect the
design and location of ACE's existing and future electric power
lines and facilities and the cost thereof, current discussions
with CORP indicate that such regulations would not significantly
impact ACE's operations.  ACE's program of Prudent Field
Management implements reasonable measures, at modest cost, to
limit magnetic field levels in the design and location of new
facilities.  Such amounts as may be necessary to comply with any
new EMF rules cannot be determined at this time and are not
included in ACE's 1996-1998 estimated construction expenditures.  
<PAGE>
     Air

     The Federal Clean Air Act, as amended, requires that all
states achieve specified primary ambient air quality standards
(relating to public health) by December 31, 1982 unless the
deadline is extended for certain pollutants for a particular
state by appropriate action taken by the EPA, and also requires
that states achieve secondary ambient air quality standards
(relating to public welfare) under the Clean Air Act within a
reasonable time.  The Clean Air Act also requires the
Administrator of the EPA to promulgate revised new source
performance standards for sulfur dioxide, particulates and
nitrogen dioxide, mandate the use of the "best technological
system of continuous emission reduction" and preclude the use of
low sulfur coal as a sole means of achieving compliance with
sulfur regulations for new power plants.  The Clean Air Act
Amendments (CAAA), which provide for penalties in the event of
noncompliance, further provide that State Implementation Plans
(SIP) contain emission limitations and such other measures as may
be necessary, as determined under regulations promulgated by the
EPA, to prevent "significant deterioration" of air quality based
on regional non-degradation classifications.

     The NJDEP is using the New Jersey Administrative Code, Title
7, Chapter 27 (NJAC 7:27) as its SIP to achieve compliance with
the national ambient air quality standards adopted by EPA under
the Clean Air Act.  NJAC 7:27 currently provides ambient air
quality standards and emission limitations, all of which have EPA
approval, for seven pollutants, including sulfur dioxide and
particulates.  ACE believes that all of its fossil fuel-fired
generating units are, in all substantial respects, currently
operating in compliance with NJAC 7:27 and the EPA approved SIP.

     In November 1990, the CAAA was enacted to provide for
further restrictions and limitations on sulfur dioxide and other
emission sources as a means to reduce acid deposition.  Phase I
of the legislation mandates compliance with the sulfur dioxide
reduction provisions of the legislation by January 1, 1995 by
utility power plants emitting sulfur dioxide at a rate of above
2.5 pounds per million BTU.  Plants utilizing certain control
technologies to meet the Phase I sulfur dioxide reductions could
be permitted, subject to EPA approval, to either postpone
compliance until 1997 or receive an early reduction bonus
allowance for reductions achieved between 1995 and 1997.  Phase
II of the legislation requires controls by January 1, 2000 on
plants emitting sulfur dioxide at a rate above 1.2 pounds per
million BTU.  

     ACE's wholly-owned B. L. England Units 1 and 2 and its
jointly-owned Conemaugh Units 1 and 2, in which ACE has a 3.83%
ownership interest, are affected by Phase I, and all of ACE's
other fossil-fueled steam generating units are affected by Phase
II.  The Keystone Station, in which ACE has a 2.47% ownership
interest, is impacted by the sulfur dioxide provisions of Title
IV of the CAAA during Phase II.  In addition, all of ACE's
fossil-fueled steam generating units will be affected by the
nitrogen oxide provisions of the CAAA.  Compliance with the
legislation will cause ACE to incur additional capital and/or
operating costs.  On April 26, 1991, the NJDEP renewed ACE's
expiring Certificates to Operate Control Apparatus or Equipment
for the three generating units at B.L. England Station for a
period of five years, expiring April 26, 1995.  A draft renewal
permit is currently under review by the NJDEP and is expected to
be issued by the end of March 1996.  The CAAA Title V operating
permit, becoming effective in 1997, will supersede the current
permitting requirements.     

     The cost of certain power purchase arrangements between ACE
and other electric utilities may also be affected by the
legislation.  A portion of the capital costs necessary to
continue compliance with the CAAA are included in ACE's current
estimate of construction expenditures shown under "Construction
and Financing" above.  ACE expects that costs associated with
compliance would be recoverable through rates, and may be offset,
in part, by utilization of certain allowances as permitted by the
CAAA, the value of which is not presently determinable.

     The CAAA requires that reductions in nitrogen oxide (NOx) be
made from the emissions of major contributing sources and each
state must impose reasonable available control technologies on
these major sources.  NJDEP regulations adopted in November 1993
require that a compliance plan be filed with the NJDEP.  ACE's
compliance plan, filed April 22, 1994, has been accepted by the
NJDEP.  Draft permits for acceptable conditions are to be
finalized before May 1996 with compliance by May 31, 1996. 
Preliminary capital expenditures are estimated at $7 million over
the next five years to achieve compliance with Phase II NOx
reductions.  The necessary emission reductions are based on
modeling results and regulatory agency discussions and could
result in additional changes to equipment and in methods of
operation and fuel, the extent of which has not been fully
determined.  

     Water

     The Federal Water Pollution Control Act, as amended (the
Clean Water Act) provides for the imposition of effluent
limitations to regulate the discharge of pollutants, including
heat, into the waters of the United States.  The Clean Water Act
also requires that cooling water intake structures be designed to
minimize adverse environmental impact.  Under the Clean Water
Act, compliance with applicable effluent limitations is to be
achieved by a National Pollution Discharge Elimination System
(NPDES) permit program to be administered by the EPA or by the
state involved if such state establishes a permit program and
water quality standards satisfactory to the EPA.  Having
previously adopted the New Jersey Pollution Discharge Elimination
System (NJPDES), NJDEP assumed authority to operate the NJPDES
permit program.  During 1981, ACE received NJPDES permits for
discharges to surface waters for all facilities with existing
EPA-issued NPDES permits.  During 1986, ACE received draft
renewal permits for both B.L. England Station and Deepwater
Station for discharges to surface waters as well as groundwater. 
ACE filed extensive comments with the NJDEP contesting the
numerous newly-imposed conditions in both permits.  The NJDEP
subsequently issued final permits for both stations containing
certain conditions which are unacceptable to ACE.  ACE filed
requests for adjudicatory hearings contesting the unacceptable
conditions contained in the permits.  ACE has reached a
resolution with the NJDEP relating to groundwater permits at B.L.
England Station which required ACE to conduct additional studies,
which were completed in 1991.  A draft NJPDES permit was issued
in February 1994 to include past contested conditions and bring
current permit limitations with respect to today's environment
and technology.  Most of the contested conditions were resolved
with the issuance of the NPDES permit renewal effective January
1, 1995.  ACE has adjudicated two minor issues related to permit
conditions requiring that a pollutant reduction and a dilution
study is being conducted to comply with the latest NJPDES
requirements.     


     Effective December 2, 1974, the NJDEP adopted new surface
water quality standards which, in part, provide guidelines for
heat dissipation from any source and which become standards for
subsequent Federal permits.  These NJDEP guidelines were included
in the final EPA permits issued for the B. L. England, Deepwater,
Salem, and Hope Creek stations.  On receipt of the permits for B.
L. England and Deepwater stations, ACE filed with the EPA a
request for alternative thermal limitations (variance) in
accordance with the provisions of Section 316(a) of the Act.  The
NJDEP and EPA have subsequently determined that B. L. England
Units 1 and 2 are in compliance with applicable thermal water
quality standards.  The request for a Section 316(a) variance for
Deepwater Station has not yet been acted upon.  ACE is not able
at this time to predict the outcome of the request, but it
believes that it has adequately supported the request for such
variance.  ACE believes that all of its wholly-owned steam
electric generating units are, in all substantial respects,
currently operating in compliance with all applicable standards
and NJPDES permit limitations, except as described herein above. 
All current surface water discharge permits for B.L. England have
been renewed as of January 1, 1995 and ACE has filed for renewal
of the ground water discharge permits for B. L. England and
surface water discharge permits for Deepwater.  
  
     The Delaware River Basin Commission (DRBC) has required
various electric utilities, as a condition of being permitted to
withdraw water from the Delaware River for use in connection with
the operation of certain electric generating stations, to provide
for a means of replacing water withdrawn from the river during
certain periods of low river flow.  Such a requirement presently
applies to the Salem and Hope Creek Stations.  As a result of
such requirement, ACE and certain other electric utilities
constructed the Merrill Creek Reservoir Project.  ACE owns a 4.8%
ownership interest in the reservoir project.   Although ACE
expects that sufficient replacement water would be provided by
Merrill Creek during periods of low river flow to permit the full
operation of Salem and Hope Creek, such events cannot be assured.

     Environmental control technology, generally, is in the
process of further development and the implementation of such may
require, in many instances, balancing of the needs for additional
quantities of energy in future years and the need to protect the
environment.  As a result, ACE cannot estimate the precise effect
of existing and potential regulations and legislation upon any of
its existing and proposed facilities and operations, or the
additional costs of such regulations.  ACE's capital expenditures
related to compliance with environmental requirements in 1995
amounted to $26.3 million, and its most recent estimate for such
compliance for the years 1996-1998 is $54 million.  Such
estimates do not include amounts which ACE may be required to
expend to comply with Phase II requirements of the CAAA at B.L.
England Unit 1 and Keystone Station or the normal costs of
compliance with radiation protection.  Such additional costs
which ACE may incur in affecting compliance with potential
regulations and legislation are not included in the estimated
construction costs for the period 1996-1998 (see "Construction
and Financing").   Future regulatory and legislative developments
may require ACE to further modify, supplement or replace
equipment and facilities, and may delay or impede the
construction and operation of new facilities, at costs which
could be substantial.  See Note 10 of the accompanying Notes to
Financial Statements for further information.   

<PAGE>
Executive Officers

     Information concerning the Executive Officers of the Company
and ACE, as of December 31, 1995, is set forth below.  Executive
Officers are elected by the respective Boards of Directors of the
Company and ACE and may be removed from office at any time by a
vote of a majority of all the Directors in office.

Name (age)                         Title(s) (effective date of         
                                   election to current position(s)
Jerrold L. Jacobs (56)          President and Chief Executive Officer
                                of the Company and Chairman and Chief
                                Executive Officer of ACE (4/26/95).
Michael J. Chesser (47)         Senior Vice President of the Company
                                and President and Chief Operating
                                Officer of ACE (4/26/95),  Director
                                of ACE. 
Michael J. Barron (46)          Vice President and Chief Financial
                                Officer of the Company and Senior
                                Vice President and Chief Financial
                                Officer of ACE (9/15/95). Director of 
                                ACE.
James E. Franklin II (49)       Vice President, Secretary and General
                                Counsel to the Company and Senior
                                Vice President, Secretary and General
                                Counsel of ACE (4/26/95), Director of
                                ACE.  
Meredith I. Harlacher, Jr.(53)  Vice President-Power System of the
                                Company and Senior Vice President-
                                Power System of ACE (4/26/95),
                                Director of ACE.
Henry K. Levari, Jr. (47)       Vice President-External Affairs of
                                the Company and Senior Vice
                                President-External Affairs of ACE
                                (4/26/95), Director of ACE.
Marilyn T. Powell (48)          Vice President of the Company and
                                Senior Vice President-Marketing of    
                                ACE (11/9/95).  Director of ACE.
Scott B. Ungerer (37)           Vice President-Enterprise Activities
                                of the Company (4/26/95).
Louis M. Walters (43)           Treasurer of the Company (4/26/95)
                                and Vice President-Treasurer and
                                Assistant Secretary of ACE (1/31/95).
Ernest L. Jolly (43)            Vice President-Human Resources and 
                                Transformation of the Company and ACE
                                (1/8/96).
J. David McCann (44)            Vice President-Strategic Customer
                                Support of ACE (4/28/93).
Henry C. Schwemm, Jr. (54)      Vice President-Power Generation & 
                                Fuels Management of ACE (4/28/93). 
<PAGE>
     Prior to election to the positions above, the following
officers held other positions with ACE (unless otherwise noted)
since January 1, 1991:

J.L. Jacobs         President and Chief Executive Officer of the
                    Company and Chairman, President and Chief
                    Executive Officer of ACE (4/28/93). 
M.J. Chesser        Senior Vice President of the Company and
                    Executive Vice President and Chief Operating
                    Officer of ACE (2/1/94).
                    Vice President-Marketing & Gas Operations,
                    Baltimore Gas & Electric Company 
M.J. Barron         Vice President and Treasurer of Maxus Energy
                    Corporation, Dallas, Texas.
J.E. Franklin II    Secretary and General Counsel to the Company
                    and ACE (1/31/95); General Counsel to the
                    Company and ACE (10/1/94); Partner in the law
                    firm Megargee, Youngblood, Franklin &
                    Corcoran, P.A. 
M.I. Harlacher, Jr. Vice President of the Company and Senior Vice
                    President-Utility Operations of ACE (8/9/91);
                    Vice President of the Company and Senior Vice
                    President-Energy Supply of ACE (4/28/93). 
M.T. Powell         Vice President of the Company and Senior Vice
                    President-Marketing of ACE (9/16/94);
                    Director of marketing process, International
                    Business Machines Corporation. 
H.K. Levari, Jr.    Vice President of the Company (8/13/86) and
                    Senior Vice President-Customer Operations of
                    ACE (9/17/94); Vice President of the Company
                    and Senior Vice President-Marketing and
                    Customer Operations of ACE (4/28/93). 
E.L. Jolly          Vice President-Atlantic Transformation of ACE
                    (5/23/94); Vice President-External Affairs of
                    ACE (3/1/92);  Station Manager Deepwater
                    Generating Station-Dupont Area for ACE.
J.D. McCann         Vice President-Power Delivery of ACE
                    (8/9/91).  
H.C. Schwemm, Jr.   Vice President-Production of ACE.
S.B. Ungerer        Vice President of the Company (1/17/94);
                    Manager, Business Planning Services (1/4/93);
                    Manager, Strategic Business Planning
                    (1/6/92);  Manager, Joint Generation. 
L.M. Walters        Vice President-Treasurer and Assistant
                    Secretary of ACE (1/31/95); Vice President-
                    Treasurer and Secretary (4/28/94); Vice
                    President-Treasurer and Assistant Secretary
                    (4/28/93); General Manager, Treasury and
                    Finance (8/1/91).
<PAGE>
ITEM 2   PROPERTIES

     Reference is made to the Financial Statements for
information regarding investment in such property by the Company
and ACE.  Substantially all of ACE's electric plant is subject to
the lien of the Mortgage and Deed of Trust under which First
Mortgage Bonds of ACE are issued.  Reference is made to Item 1 -
Business "General" and "Energy Requirements and Power Supply" for
information regarding ACE's properties.  Information concerning
leases is set forth in Note 10 of ACE's Notes to Financial
Statements incorporated herein by reference.  Information
regarding electric generating stations is set forth in Item 1,
Business-"Energy Requirements and Power Supply."


ITEM 3   LEGAL PROCEEDINGS

     Reference is made to Item 1-Business and the Notes to
Financial Statements of the Company (Notes 3 and 10) and ACE
(Notes 3 and 8) for information regarding various pending
administrative and judicial proceedings involving rate and
operating and environmental matters, respectively. 

ITEM 4   SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
     Not Applicable

PART II
ITEM 5   MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
         STOCKHOLDER MATTERS

     The Company's Common Stock is listed on the New York Stock
Exchange.  All of ACE's Common Stock is owned by the Company.  At
December 31, 1995, there were 48,683 holders of record of the
Company's Common Stock.  The following table indicates the high
and low sale prices for the Company's Common Stock as reported in
the Wall Street Journal-Composite Transactions, and dividends
paid for the periods indicated:
                                                      Dividends
                                  High      Low       per Share
Common Stock:
 1995
     First Quarter             $19.000   $17.750       $ .385
     Second Quarter            $19.625   $17.875       $ .385
     Third Quarter             $19.875   $18.125       $ .385
     Fourth Quarter            $20.125   $19.000       $ .385

  1994
     First Quarter             $21.750   $19.875       $ .385
     Second Quarter            $21.500   $16.375       $ .385
     Third Quarter             $19.625   $16.125       $ .385
     Fourth Quarter            $18.250   $16.000       $ .385


     The funds required to enable the Company to pay dividends on
its Common Stock are derived primarily from the dividends paid by
ACE on its Common Stock, all of which is held by the Company. 
Therefore the ability of the Company to pay dividends on its
Common Stock will be governed by the ability of ACE to pay
dividends on its Common Stock.  The rate and timing of future
dividends of the Company will depend upon the earnings and
financial condition of the Company and its subsidiaries,
including ACE, and upon other factors affecting dividend policy
not presently determinable.  ACE is subject to certain
limitations on the payment of dividends to the Company.  Whenever
full dividends on Preferred Stock have been paid for all past
quarter-yearly periods, ACE may pay dividends on its Common Stock
from funds legally available for such purpose.  Until all
cumulative dividends have been paid upon all series of Preferred
Stock and until certain required sinking fund redemptions of such
Preferred Stock have been made, no dividend or other distribution
may be paid or declared on the Common Stock of ACE and no Common
Stock of ACE shall be purchased or otherwise acquired for value
by ACE.  In addition, as long as any Preferred Stock is
outstanding, ACE may not pay dividends or make other
distributions to the holder of its Common Stock if, after giving
effect to such payment or distribution, the capital of ACE
represented by its Common Stock, together with its surplus as
then stated on its books of account, shall in the aggregate, be
less than the involuntary liquidation value of the then
outstanding shares of Preferred Stock.  
<PAGE>
ITEM 6   SELECTED FINANCIAL DATA
     Selected financial data for the Company and ACE for each of
the last five years is listed below. 
<TABLE>
<CAPTION>
Atlantic Energy, Inc.
                        1995        1994          1993          1992        1991
                                   (Thousands of Dollars)
<S>                  <C>          <C>         <C>          <C>         <C>
Operating
 Revenues            $ 953,137    $ 913,039   $  865,675   $  816,825  $  808,374   
Net Income           $  81,768    $  76,113   $   95,297   $   86,210  $   85,635   
Earnings per Average
  Common Share       $    1.55    $    1.41   $     1.80   $     1.67  $     1.75   
Total Assets
 (Year-end)          $2,620,896   $2,545,555  $2,487,508   $2,219,338   $2,151,416
Long Term Debt and
 Redeemable Preferred
 Stock (Year-end)(b) $1,032,103   $  940,788  $  952,101   $  842,236  $  807,347
 Capital Lease
 Obligations
 (Year-end)(b)       $   40,886   $   42,030  $   45,268   $   49,303  $   53,093 
 Common Dividends
 Declared            $     1.54   $     1.54  $    1.535   $    1.515  $    1.495  
</TABLE> 
<TABLE>
<CAPTION>
Atlantic City Electric Company 
 

                        1995        1994          1993          1992        1991
                                   (Thousands of Dollars)
 <S>                 <C>           <C>          <C>          <C>         <C>
Operating 
  Revenues           $ 953,779     $  913,226   $  865,799   $  816,931  $  808,482
Net Income           $  98,752     $   93,174   $  109,026   $  107,446  $  107,428 
Earnings for Common 
 Shareholder (a)     $  84,125     $   76,458   $   91,621   $   89,634  $   91,017 
Total Assets
  (Year-end)         $2,461,907    $2,421,316   $2,363,584   $2,100,278  $2,042,859 
Long Term Debt and
 Redeemable Preferred
 Stock (Year-end)(b) $  951,603    $  924,788   $  937,101   $  817,108  $  768,247 
Capital Lease
 Obligations
 (Year-end)(b)       $   40,877    $   42,030   $   45,268   $   49,303  $   53,093 
 Common Dividends
 Declared (a)        $   81,239    $   83,482   $   81,347   $   78,336  $   74,073 
   
  
(a)  Amounts shown as total, rather than on a per-share basis, since ACE is a
     wholly-owned subsidiary of the Company.
(b)  Includes current portion.
/TABLE
<PAGE>
ITEM 7  Management's Discussion and Analysis of Financial 
                      Condition and Results of Operations

      
Financial Summary

     Consolidated operating revenues for 1995, 1994 and 1993 were
$953.1 million, $913.0 million and $865.7 million, respectively.  The
increase in 1995 revenue over 1994 largely reflects a provisional
increase in annual Levelized Energy Clause (LEC) revenues of $37.0
million granted in July 1995 and an increase in unbilled revenues. 
The increase in 1994 revenue from 1993 was primarily due to an
increase of $55.0 million in LEC revenues effective July 1994,
accompanied by an increase in sales of energy.  

     Consolidated earnings per share for 1995 were $1.55 on net income
of $81.8 million, compared with $1.41 on net income of $76.1 million
in 1994 and $1.80 on net income of $95.3 million in 1993.  The 1994
and 1993 earnings include reductions of $.37 and $.10 for special
charges, respectively.  Excluding the 1994 special charges, 1995
earnings per share decreased from 1994 primarily due to reduced sales
of energy.  Contributions to consolidated earnings per share were as
follows:

                        1995           1994           1993    
Utility                $1.59          $1.41          $1.73  
Nonutility              (.04)           -              .07

 
     The quarterly dividend paid on Common Stock was $.385 per share,
or an annual rate of $1.54 per share.  Information with respect to
Common Stock is as follows:


                                    1995        1994        1993    
Dividends Paid Per Share          $ 1.54      $ 1.54      $ 1.53  
Book Value Per Share              $15.48      $15.56      $15.62  
Annualized Dividend Yield            8.0%        8.7%        7.0%
Return on Average Common Equity      9.9%        9.1%       11.7%
Total Return (Dividends paid
 plus change in share price)        18.0%      (11.9)%       0.6%
Market to Book Value                 124%        113%        139% 
Price/Earnings Ratio                  12          13          12  
Year End Closing Price-NYSE       $19.25      $17.63      $21.75     

Liquidity and Capital Resources

Atlantic Energy, Inc.

Atlantic Energy, Inc. (AEI, Company or parent) is the parent of
Atlantic City Electric Company (ACE) and Atlantic Energy Enterprises,
Inc. (AEE), which are wholly-owned subsidiaries.  The Company's cash
flows are dependent on the cash flows of its subsidiaries, primarily
ACE.  

<PAGE>
Principal cash inflows of the Company were as follows:

                               1995        1994        1993
(millions)
Dividends from ACE            $81.2       $83.2       $81.3       
Credit Facility                34.5         -           -         
Dividend Reinvestment            
 and Stock Purchase Plan        -           6.7        16.2  

     In September 1995, AEI established a $75 million revolving credit
and term loan facility.  The revolver is comprised of a 364-day senior
revolving credit facility in the amount of $35 million and a three-
year senior revolving credit facility in the amount of $40 million. 
Interest rates on borrowings are based on senior debt ratings and on
the borrowing option selected by the Company.  As of December 31,
1995, AEI had $34.5 million outstanding.  This facility can be used to
fund further acquisitions of Company Common Stock and for other
general corporate purposes.

Principal cash outflows of the Company were as follows:
                                                                      
                                   1995       1994       1993 
(Millions)
Dividends to Shareholders         $81.2      $83.2      $81.3
Advances and Capital  
 Contributions to Subsidiaries*    (6.7)      25.6       29.8
Common Stock Reacquisitions        29.6        3.9        -
Loans to Subsidiaries               7.5         -         -    
* Net of repayments

     The Company has a program to reacquire up to three million shares
of the Company's Common Stock outstanding.  There is no schedule or
specific share price target associated with the reacquisitions.  The
authorized number of shares is not to be affected.  During 1995, the
Company reacquired and cancelled 1,625,000 shares for a total cost of
$29.6 million with prices ranging from $17.625 to $18.875 per share. 
At December 31, 1995, the Company has reacquired and cancelled
1,846,700 shares of its Common Stock at a total cost of $33.5 million.

     Current year Dividends Declared on Common Stock as presented on
the Consolidated Statement of Cash Flows includes the effects of
market purchases of Common Stock with reinvested dividends as
instituted since July 1994. Prior to this, funds were available to the
Company from the issuance of original shares through optional cash
purchases and reinvested dividends.
 
     Agreements between the Company and its subsidiaries provide for
allocation of tax liabilities and benefits generated by the respective
subsidiaries.  A separate credit support agreement exists between the
Company and ATE. 






Atlantic City Electric Company

     ACE is a public utility primarily engaged in the generation,
transmission, distribution and sale of electric energy.  ACE's service
territory encompasses approximately 2,700 square miles within the
southern one-third of New Jersey with the majority of customers being
residential and commercial.  ACE, with its wholly-owned subsidiary
that operates certain generating facilities, is the principal
subsidiary within the consolidated group.  Cash construction
expenditures for 1993-1995 amounted to $359.0 million and included
expenditures for upgrades to existing transmission and distribution
facilities and compliance with provisions of the Clean Air Act
Amendments (CAAA) of 1990.  ACE's current estimate of cash
construction expenditures for 1996-1998  is $255 million.  These
estimated expenditures reflect necessary improvements to generation,
transmission and distribution facilities.

     ACE also utilizes cash for mandatory redemptions of Preferred
Stock and maturities and redemption of long term debt.  Optional
redemptions of securities are reviewed on an ongoing basis with a view
toward reducing the overall cost of capital.  Redemptions of Preferred
Stock (at par or stated value) for the period were as follows:
 
                                    1995      1994      1993 
Preferred Stock
  (Series)      
   9.96% (Shares)                     -         -       48,000 
  $8.53  (Shares)                  240,000   240,000      -    
  $8.25  (Shares)                    5,000     5,000     5,000
 
  Aggregate Amount (000)           $24,500   $24,500    $5,300

First Mortgage Bonds redeemed, acquired and retired or matured
in the period 1993-1995 were as follows:

    Date                 Series            Principal     Price(%)      
                                             Amount                    
                                              (000)
October 1995         9-1/4% due 2019       $ 53,857      105.15
October 1995        10-1/2% due 2014            850      101.00  
November 1994        7-5/8% due 2005          6,500      100.00
June 1994           10-1/2% due 2014         23,150      102.00
Various 1994 Dates   9-1/4% due 2019         11,910      105.38*
September 1993       9-1/4% due 2019         69,233      110.95*
September 1993       8-7/8% due 2016        125,000      104.80
March 1993           8-7/8% due 2000         19,000      102.41
March 1993           8%     due 2001         27,000      102.53
March 1993           8%     due 1996         95,000      100.91
March 1993           4-3/8% due 1993          9,540      100.00

* Average price

     Scheduled debt maturities and sinking fund requirements aggregate
$113.8 million for 1996-1998.

     On or before April 1 of each year, ACE and other New Jersey
utilities are required to pay excise taxes to the State of New Jersey. 
In March 1995, ACE paid $98.7 million funded  through the issuance of
short term debt.  In 1994 and 1993, ACE paid an additional $50 million
and $45 million, respectively, for the accelerated payment of one
year's tax due as required by amended state law.  These accelerated
payments are being recovered through rates.

     During 1995, ACE made $19.1 million in payments related to its
workforce reduction program.  ACE expects payments and settlement of
the remaining obligation for this program of $7.5 million to be
substantially completed by the end of 1996. 

     On an interim basis, ACE finances construction costs and other
capital requirements in excess of internally generated funds through
the issuance of unsecured short term debt consisting of commercial
paper and borrowings from banks.  As of December 31, 1995, ACE has
arranged for lines of credit of $150 million of which $119.5 million
was available.  Permanent financing by ACE is undertaken by the
issuance of long term debt and Preferred Stock, and at times from
capital contributions by AEI.  ACE's nuclear fuel requirements
associated with its jointly-owned units have been financed through
arrangements with a third party.

     A summary of the issue and sale of ACE's long term debt for 1993-
1995 is as follows:

(millions)                  1995       1994       1993   
First Mortgage Bonds          -          -        $225
Medium Term Notes           $105         -         240
Pollution Control Bonds       -         $55          4

     The proceeds from these financings were used to refund higher
cost debt and for construction purposes.  During 1996-1998, ACE may
issue up to $150 million in new long term debt to be used for 
construction and repayment of short term debt.  The provisions of
ACE's charter, mortgage and debenture agreements can limit, in certain
cases, the amount and type of additional financing which may be used. 
At December 31, 1995, ACE estimates additional funding capacities of
$288 million of First Mortgage Bonds, or $490 million of Preferred
Stock, or $413 million of unsecured debt.  These amounts are not
necessarily additive.

Atlantic Energy Enterprises, Inc.

     On January 1, 1995, AEI transferred direct ownership of its
existing nonutility companies to AEE.  AEE is a holding company which
is responsible for the management of the investments in the nonutility
companies consisting of:  Atlantic Generation, Inc. (AGI); Atlantic
Southern Properties, Inc. (ASP); ATE Investment, Inc. (ATE); Atlantic
Thermal Systems, Inc. (ATS); CoastalComm, Inc. (CCI) and Atlantic
Energy Technology, Inc. (AET).  Also, AEE has a 50% equity interest in
a limited liability company which provides energy management services,
including natural gas supply, transportation and marketing. Management
of the nonutility companies has developed a five-year business
strategy to expand operations and improve its financial performance. 
AEE's business strategy reflects the potential investment of
approximately $400 million over the next five years.    

Atlantic Generation, Inc.

     AGI and its wholly-owned subsidiaries are engaged in the
development, acquisition, ownership and operation of cogeneration
power projects.  AGI's activities through its subsidiaries are
primarily represented by partnership interests in three cogeneration
facilities located in New Jersey and New York.  At December 31, 1995,
total investments in these partnerships amounted to $30.6 million. 
Cash outlays for capital investments  by AGI for 1993-1995 totaled
$7.5 million.  AGI obtained the funds for its investments through
capital contributions from AEI.  
Atlantic Southern Properties, Inc.

     ASP owns and manages a 280,000 square-foot commercial office and
warehouse facility located in southern New Jersey with a net book
value of $10.1 million at December 31, 1995.  This investment has been
funded by capital contributions from AEI and borrowings under a loan
agreement with ATE.  

ATE Investment, Inc.

     ATE provides funds management and financing to affiliates and
manages a portfolio of investments in leveraged leases.  ATE has
invested $79.0 million in leveraged leases of three commercial
aircraft and two containerships.  ATE obtained funds for its business
activities and loans to affiliates through capital contributions from
AEI and external borrowings.  These borrowings include $15 million
principal amount of 7.44% Senior Notes due 1999 and a revolving credit
and term loan facility of up to $25 million.  At December 31, 1995,
$18.5 million was outstanding under this facility.  ATE's cash flows
are provided from lease rental receipts and realization of tax
benefits generated by the leveraged leases.  ATE has notes receivable,
including interest, outstanding with ASP which totaled $9.4 million at
December 31, 1995.  ATE has established a $10 million revolving credit
agreement with ATS, of which $522 thousand was receivable,  including
interest, from ATS at December 31, 1995.  ATE has established credit
arrangements with AEE, of which $9.6 million was receivable, including
interest, from AEE at December 31, 1995.    

Atlantic Thermal Systems, Inc.

     ATS and its wholly-owned subsidiaries are engaged in the
development and operation of thermal heating and cooling systems.  ATS
has invested $11.9 million as of December 31, 1995.  ATS is authorized
to make $88 million in capital expenditures related to a district
heating and cooling system to serve the business and casino district
in Atlantic City, New Jersey.  ATS has obtained funds for its project
development through loans from AEI and has established a $10 million
revolving credit agreement with ATE.  Additional funding for the
project is expected from $12.5 million borrowed from the proceeds of
bonds issued by the New Jersey Economic Development Authority with an
initial rate of interest of 3.70%.  These funds are currently
restricted in trust pending resolution of certain loan conditions. 
Satisfaction of these conditions and use of the funds is expected in
1996.   

CoastalComm, Inc.

     Formed in November 1995, CCI invested $5.2 million in a joint
venture pursuing telecommunication technology. 

Atlantic Energy Technology, Inc. 

     AET is currently concluding the affairs of its subsidiary, which
is its sole investment.  The net investment in this subsidiary is
nominal. Provisions for the write down of this investment to its
current book value had been made in prior years.  There are no future
plans for investment activity at this time by AET.

RESULTS OF OPERATIONS

     Operating results are dependent upon the performance of the
subsidiaries, primarily ACE.  Since ACE is the principal subsidiary
within the consolidated group, the operating results presented in the
Consolidated Statement of Income are those of ACE, after elimination
of transactions among members of the consolidated group.  Results of
the nonutility companies are reported in Other Income.

Revenues

     Operating Revenues - Electric increased 4.4% and 5.5% in 1995 and
1994, respectively. Components of the overall changes are shown as
follows:

                                         1995         1994         
(millions)       
Levelized Energy Clause                $ 49.2        $30.3
Kilowatt-hour Sales                     (10.0)         9.6        
Unbilled Revenues                        16.6         (7.3)       
Sales for Resale                        (11.9)        17.8       
Other                                    (3.8)        (3.0)       
Total                                  $ 40.1        $47.4

     LEC revenues increased in 1995 due to a provisional rate increase
of $37.0 million in July 1995 and a $55 million increase in July 1994. 
Changes in kilowatt-hour sales are discussed under "Billed Sales to
Ultimate Utility Customers."  Overall, the combined effects of changes
in rates charged to customers and kilowatt-hour sales resulted in
increases of 5.9% and 3.1% in revenues per kilowatt-hour in 1995 and
1994, respectively.  The changes in Unbilled Revenues are a result of
the amount of kilowatt-hours consumed by, but not yet billed to,
ultimate customers at the end of the respective periods, which are
affected by weather and economic conditions, and the corresponding
price per kilowatt-hour.  The changes in Sales for Resale are a
function of ACE's energy mix strategy, which in turn is dependent upon
ACE's needs for energy, the energy needs of other utilities
participating in the regional power pool of which ACE is a member, and
the sources and prices of energy available.  The decline in the 1995
Sales for Resale reflects a decrease in the demand of the power pool,
the decline in market prices and a reduction in excess energy sources
when compared to the previous year.  The decrease in supplemental
excess energy sources reflect the expiration of a 200 megawatt
purchase capacity arrangement in May 1994, and expiration of other
short term purchase contracts.  The increase in Sales for Resale for
1994 was the result of being able to meet the demands of the regional
power pool due to the extreme weather conditions during the first six
months of 1994.  

Billed Sales to Ultimate Utility Customers

     Changes in kilowatt-hour sales are generally due to changes in
the average number of customers and average customer use, which is
affected by economic and weather conditions.  Energy sales statistics,
stated as percentage changes from the previous year, are shown as
follows:

                        1995                      1994  
                         Avg    Avg #              Avg    Avg #
Customer Class   Sales   Use   of Cust     Sales   Use   of Cust
Residential      (2.0)% (3.1)%  1.2%        1.5 %  .4 %  1.1%
Commercial        1.4    (.1)   1.5         2.6    .5    2.1
Industrial       (7.4)  (9.0)   1.7        (2.9) (3.8)    .9
Total            (1.4)  (2.6)   1.2         1.3    -     1.2
      
     The 1995 decrease in total sales was attributable to weather
conditions that led to below normal electricity consumption for a
majority of the year and a decreased number of billing days in 1995
compared to 1994.  The 1994 increase in total sales was due to an
increase in the number of billing days in 1994 compared to 1993 and,
to a lesser extent, weather.  The Commercial sector experienced
continued growth during 1995 due to sales increases across all the
major commercial subsectors.  Commercial growth in both years
benefitted from night lighting programs.  The sales declines in the
Industrial sector are primarily related to the impact of two former
customers taking energy service from independent power producers
commencing in June 1994 and January 1995.    

Costs and Expenses 

     Total Operating Expenses increased 5.9% and 7.6% in 1995 and
1994, respectively.  Included in these expenses are the costs of
energy, purchased capacity, operations, maintenance, depreciation and
taxes.  

     Energy expense reflects costs incurred for energy needed to meet
load requirements, various energy supply sources used and operation of
the LECs.  Changes in costs reflect the varying availability of low-
cost generation from ACE-owned and purchased energy sources, and the
corresponding unit prices of the energy sources used, as well as
changes in the needs of other utilities participating in the PJM power
pool.  The cost of energy is recovered from customers primarily
through the operation of the LEC.  Excluding the effects of SNJEI
(discussed below), earnings generally are not affected by energy costs
because these costs are adjusted to match the associated LEC revenues. 
In any period, the actual amount of LEC revenue recovered from
customers may be greater or less than the actual amount of energy cost
incurred in that period.  Such respective overrecovery or
underrecovery of energy costs is recorded on the Consolidated Balance
Sheet as a liability or an asset as appropriate.  Amounts in the
balance sheet are recognized in the Consolidated Statement of Income
within Energy expense during the period in which they are subsequently
recovered through the LEC.  ACE was underrecovered by $31.4 million
and by $11 million at December 31, 1995 and 1994, respectively.  The
increase in 1995 is due to the combination of the election to defer
recovery of $20.6 million of recoverable fuel costs, lower than
projected kilowatt-hour sales and greater than projected purchased
fuel as replacement for Salem Station generation.  

     As a result of implementing the Southern New Jersey Economic
Initiative (SNJEI), ACE is forgoing the recovery of energy costs in
LEC rates in the amount of $10.0 million and $28.0 million for the
1995 and 1994 LEC periods, respectively.  After tax net income has
been reduced by $12.2 million and $10.1 million due to the effects of
the initiative for 1995 and 1994, respectively.

     Energy expense decreased 9.0% in 1995 primarily due to the
increase in underrecovered fuel costs, offset in part by the effects
of the SNJEI referred to above.  In 1994, Energy expense increased
32.7% due to the SNJEI and the increase in the levelized energy clause
that reduced underrecovered fuel costs. Production-related energy
costs for 1995 decreased 1.9% due to reduced generation.  The average
unit cost of energy decreased to 2.02 cents per kilowatt-hour in 1995
compared to 2.04 cents per kilowatt-hour in 1994.  Production-related
energy costs for 1994 increased by 19.9% due to increased overall
generation and the high cost of energy from additional nonutility
sources.  The 1993 cost per kilowatt-hour was 1.82 cents.  

     Purchased Capacity expense reflects entitlement to generating
capacity owned by others.  Purchased Capacity expense increased 45.5%
and 18.2% in 1995 and 1994, respectively.  The increases  reflect
additional contract capacity supplied by nonutility power producers in
each year.

     Operations expense decreased 2.8% and 3.5% in 1995 and 1994,
respectively.  These decreases reflect the benefits of ACE's
restructuring programs, initiated in 1993 and 1994.  The 1995 decrease
was offset in part by the additional costs associated with Salem
Station restart activities.  Net after tax savings approximated $8
million in 1995 related to the workforce reduction recorded in 1994. 
Employee separations throughout ACE of approximately 300 employees
largely occurred on March 1, 1995.  The original estimate of net after
tax savings of $10 million was based on a full-year assessment. 
Maintenance expense decreased 8.5% and 17.2% in 1995 and 1994,
respectively, due to cost saving measures. 

     Depreciation and Amortization expense increased 7.0% and 7.9% in
1995 and 1994, respectively, as a result of continued increases in
ACE's depreciable electric plant in service.  
<PAGE>
     State Excise Taxes expense increased 5.9% in 1995 due to an
increase in the tax base used to calculate the tax in comparison to
the 1994 tax base.  In 1994, State Excise Taxes expense decreased 6.9%
relative to the higher tax assessment in 1993.
   
     Federal Income Taxes increased 7.9% in 1995 and decreased 6.1% in
1994 as a result of the level of taxable income during those periods. 

     Employee Separation costs is the provision by ACE in 1994 for the
reduction of its workforce.  Other-Net within Other Income (Expense)
decreased in 1994 due to the net after-tax impacts of the write-off of
deferred nuclear study costs of $1.4 million and the write-down of the
carrying value of ASP's commercial property of $1.7 million.  The
Litigation Settlement for 1993 represents an additional allocation to
customers of the proceeds from the 1992 settlement associated with the
Peach Bottom Station shut down in prior years.  
  
     Interest on Long Term Debt increased 5.2% in 1995 due to
increased amounts of debt outstanding during the year.  In 1994,
interest on long term debt decreased 3.4% due to refunding of higher
cost debt.  At December 31, 1995, 1994 and 1993, ACE's embedded cost
of long term debt was 7.5%, 7.6% and 7.8%, respectively.  

     Preferred Stock Dividend Requirements decreased 12.5% and 4% in
1995 and 1994, respectively, as a result of continuing mandatory and
optional redemptions.  Embedded cost of Preferred Stock as of December
31, 1995, 1994 and 1993 was 7.4%, 7.6% and 7.7%, respectively.

Outlook

     Over the next five years, AEI will devote considerable resources
to the development of energy-related businesses and markets.  AEE's
business plan calls for additional investments of $400 million.  AEE's
investment strategy will further its long term objectives of becoming
a wholesale energy supplier and aggregator as well as a provider of
energy services for its customers.  AEE also expects to make
additional investments in energy-related technologies and services
while continuing to pursue strategic business alliances and services
that will support its growth and financial performance.  AEE's
business plan indicates a positive contribution to earnings in 1996.

     Throughout this period, however, ACE's utility business will
continue to be the primary factor influencing the Company's overall
financial performance.  Factors such as regional economic trends,
abnormal weather conditions and inflation will continue to be
important determinants of ACE's financial performance. However,
continued competition from independent power producers and the
anticipated deregulation of the electric utility industry are becoming
the most critical strategic factors for ACE.
  
     Fundamental changes in the industry have led to the emergence of
significant competitive issues for ACE, including heightened
competition in the wholesale bulk power market, the growth of the
independent power industry and the pressure to offer more competitive
rates to customers.   

     ACE is closely monitoring deregulation of the industry on both a
state and Federal level.  The Federal Energy Regulatory Commissions'
(FERC) on-going rulemaking proceeding is proposing changes to rules
governing transmission access and pricing.  FERC is also establishing
guidelines for recovery of stranded costs and investments stemming
from wholesale transactions.  In response to FERC's initiative, the
power pool in which ACE participates has proposed significant changes
to its structure and operation.

     State jurisdictions across the country, including New Jersey, are
closely examining the issues surrounding deregulation or are creating
new regulations designed to foster a more competitive industry.  ACE
is playing an active role in the BPUs on-going Energy Master Plan
proceeding.  Among other things, the proceeding is investigating the
extent to which utilities, in a competitive environment, may be
threatened with the inability to recover investments or long term
commitments prudently made, and placed into rates under traditional
ratemaking regulations.  To date, the BPU has made no formal policy
pronouncement regarding deregulation or the recovery of stranded
commitments.
     
In anticipation of heightened competition in energy markets, ACE is
pursuing a number of initiatives designed to strengthen its position
in the marketplace.  The cost of ACE's power supply, including the
cost of power purchased from independent power producers, along with
its retail prices are expected to be critical success factors in a
competitive marketplace.  ACE is focusing on cost and rate control
measures as well as the development of new energy-related products and
services.  To allow for more flexibility and closer cost control, ACE
transferred its production operations to its subsidiary, Deepwater
Operating Company, on January 1, 1996.  Alternate pricing mechanisms
and long term discount power contracts are being explored as a means
of retaining key customers that are at risk of leaving ACE's system. 
While any such discounts are intended to have a long term beneficial
impact, they could have a detrimental effect on ACE's operating
revenues and net income in the short term.  

ACE's net income and its levelized energy adjustment rates may be
affected by the operational performance of nuclear generating
facilities and a BPU-mandated nuclear unit performance standard. Net
income may also be affected by significant changes in the
decommissioning costs associated with the nuclear units.  At this
time, it is not known what impact there may be on future operations
and financial condition associated with the uncertain status of Salem
Station Unit 1.

The electric utility industry continues to be capital intensive.  ACE
has lowered its planned construction budget to $398 million for 1996-
2000, with an expected reduction in its external cash requirements. 
ACE's ability to generate cash flows or access the capital markets to
fund capital requirements will be affected by competitive pressures on
revenues and net income, as well as regulatory initiatives and rate
developments.

The FASB issued two new statements in 1995 - Statement No. 121
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of" and Statement No. 123 "Accounting for Stock-
Based Compensation".  Both statements are effective for the Company in
1996.  Statement No. 121 primarily concerns accounting for the
impairment and disposal of property, plant and equipment.  Statement
No. 123 permits a fair value-based method to account for stock-based
compensation as an alternative to the intrinsic value-based method
currently permitted.  The Company currently employs stock-based
compensation which has not had a material impact on the financial
statements.  The Company has not yet fully assessed the impacts on its
financial statements of the requirements of these new accounting
standards. 

Inflation

Inflation affects the level of operating expenses and also the cost of
new utility plant placed in service.  Traditionally, the rate making
practices that have applied to ACE have involved the use of historical
test years and the actual cost of utility plant.  However, the ability
to recover increased costs through rates, whether resulting from
inflation or otherwise, depends upon both market circumstances and the
frequency, timing and results of rate case decisions.  
 <PAGE>
ITEM 8    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF MANAGEMENT

The management of Atlantic Energy, Inc. and its subsidiaries (the
Company) is responsible for the preparation of the financial
statements presented in this Annual Report.  The financial statements
have been prepared in conformity with generally accepted accounting
principles.  In preparing the financial statements, management made
informed judgments and estimates, as necessary, relating to events and
transactions reported.  

Management has established a system of internal accounting and
financial controls and procedures designed to provide reasonable
assurance as to the integrity and reliability of financial reporting. 
In any system of financial reporting controls, inherent limitations
exist.  Management continually examines the effectiveness and
efficiency of this system, and actions are taken when opportunities
for improvement are identified.  Management believes that, as of
December 31, 1995, the system of internal accounting and financial
controls over financial reporting is effective.  Management also
recognizes its responsibility for fostering a strong ethical climate
in which the Company's affairs are conducted according to the highest
standards of corporate conduct.  This responsibility is characterized
and reflected in the Company's code of ethics and business conduct
policy.

The financial statements have been audited by Deloitte & Touche LLP,
Certified Public Accountants.  Deloitte & Touche provides objective,
independent audits as to management's discharge of its
responsibilities insofar as they relate to the fairness of the
financial statements.  Their audits are based on procedures believed
by them to provide reasonable assurance that the financial statements
are free of material misstatement.

The Company's internal auditing function conducts audits and
appraisals of the Company's operations.  It evaluates the system of
internal accounting, financial and operational controls and compliance
with established procedures.  Both the external auditors and the
internal auditors periodically make recommendations concerning the
Company's internal control structure to management and the Audit
Committee of the Board of Directors.  Management responds to such
recommendations as appropriate in the circumstances.  None of the
recommendations made for the year ended December 31, 1995 represented
significant deficiencies in the design or operation of the Company's
internal control structure.


J. L. Jacobs                                             
President and Chief Executive Officer


M. J. Barron
Vice President and Chief Financial Officer

February 2, 1996
<PAGE>
REPORT OF THE AUDIT COMMITTEE

The Audit Committee of the Board of Directors is comprised solely of
independent directors.  The members of the Committee are:  Matthew
Holden, Jr., Kathleen MacDonnell, Bernard J. Morgan and Harold J.
Raveche.  The Committee held five meetings during 1995.

The Committee oversees the Company's financial reporting process on
behalf of the Board of Directors.  In fulfilling its responsibility,
the Committee recommended to the Board of Directors, subject to
shareholder ratification, the selection of the Company's independent
auditors, Deloitte & Touche LLP.  The Committee discussed with the
Company's internal auditors and Deloitte & Touche the overall scope of
and specific plans for their respective activities concerning the
Company.  The Committee meets regularly with the internal and external
auditors, without management present, to discuss the results of their
activities, the adequacy of the Company's system of accounting,
financial and operational controls and the overall quality of the
Company's financial reporting.  The meetings are designed to
facilitate any private communication with the Committee desired by the
internal and external auditors.  No significant actions by the
Committee were required during the year ended December 31, 1995 as a
result of any communications conducted.



Matthew Holden, Jr.
Chairman, Audit Committee

February 2, 1996 
<PAGE>
INDEPENDENT AUDITORS' REPORT
                                                    




To the Shareholders and the Board of Directors
of Atlantic Energy, Inc.:

We have audited the accompanying consolidated balance sheets of
Atlantic Energy, Inc. and subsidiaries as of December 31, 1995 and
1994 and the related consolidated statements of income, changes in
common shareholders' equity, and cash flows for each of the three
years in the period ended December 31, 1995.  These financial
statements are the responsibility of the Company's management.  Our
responsibility is to express an opinion on these financial statements
based on our audits.

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

In our opinion, such consolidated financial statements present fairly,
in all material respects, the financial position of Atlantic Energy,
Inc. and subsidiaries at December 31, 1995 and 1994 and the results of
their operations and their cash flows for each of the three years in
the period ended December 31, 1995 in conformity with generally
accepted accounting principles.



DELOITTE & TOUCHE LLP
Parsippany, New Jersey  

February 2, 1996 















<PAGE>
CONSOLIDATED STATEMENT OF INCOME     
(Thousands of Dollars)                  
                                    For the Years Ended December 31,
                                     1995         1994         1993 
Operating Revenues-Electric        $953,137     $913,039     $865,675 

Operating Expenses:
Energy                              191,766      210,891      159,438
Purchased Capacity                  190,570      130,929      110,781
Operations                          152,060      156,409      162,151
Maintenance                          34,379       37,568       45,360
Depreciation and Amortization        78,461       73,344       67,950
State Excise Taxes                  102,811       97,072      104,280
Federal Income Taxes                 45,876       42,529       45,277
Other Taxes                           8,677       10,757       10,854
Total Operating Expenses            804,600      759,499      706,091

Operating Income                    148,537      153,540      159,584

Other Income and Expense:
Allowance for Equity Funds Used 
 During Construction                    817        3,634        2,368
Employee Separation Costs, 
 net of tax benefit of $9,265          -         (17,335)        -  
Litigation Settlement, net of tax 
 benefit of $1,321                     -            -          (2,564)
Other-Net                             8,241        8,678       12,884 
Total Other Income and Expense        9,058       (5,023)      12,688

Income Before Interest Charges      157,595      148,517      172,272  

Interest Charges:
Interest on Long Term Debt           60,329       57,346       59,385
Other Interest Expense                2,550        1,114        1,633
Total Interest Charges               62,879       58,460       61,018
Allowance for Borrowed Funds             
 Used During Construction            (1,679)      (2,772)      (1,448)
Net Interest Charges                 61,200       55,688       59,570
Less Preferred Stock Dividend              
 Requirements of Subsidiary          14,627       16,716       17,405

Net Income                         $ 81,768     $ 76,113     $ 95,297
                                                         
Average Number of Shares of Common                        
 Stock Outstanding(in thousands)     52,815       54,149       52,888
Per Common Share:
Earnings                              $1.55        $1.41        $1.80
Dividends Declared                    $1.54        $1.54        $1.535
Dividends Paid                        $1.54        $1.54        $1.53


The accompanying Notes to Consolidated Financial Statements are an 
integral part of these statements.



CONSOLIDATED STATEMENT OF CASH FLOWS    
(Thousands of Dollars)
                                      For the Years Ended December 31,
                                         1995       1994       1993
Cash Flows Of Operating Activities:
Net Income                            $ 81,768   $ 76,113   $ 95,297
Deferred Purchased Power Costs          15,721     14,920     (6,050)
Deferred Energy Costs                  (20,435)    (3,819)   (15,269)
Preferred Stock Dividend Requirements   14,627     16,716     17,405
Depreciation and Amortization           78,461     73,344     67,950
Deferred Income Taxes-Net               25,946     17,863     20,901
Unrecovered State Excise Taxes           9,560    (40,128)   (33,706)
Employee Separation Costs              (19,112)    26,600       - 
Net (Increase) Decrease in Other         
 Working Capital                       (43,068)   (21,472)    30,088 
Other-Net                                4,893     (2,457)     1,534
Net Cash Provided by Operating       
 Activities                            148,361    157,680    178,150
Cash Flows Of Investing Activities:
Utility Construction Expenditures     (100,904)  (119,961)  (138,111)
Leased Property                        (10,446)   (10,713)    (9,946)
Decommissioning Trust Fund Deposits     (6,424)    (6,424)    (6,424) 
Other-Net                              (22,596)   (11,276)    (9,832)
Net Cash Used by Investing Activities (140,370)  (148,374)  (164,313)

Cash Flows Of Financing Activities:
Proceeds from Long Term Debt           168,904     54,572    464,633
Retirement and Maturity of Long Term     
 Debt                                  (57,489)   (42,664)  (370,541)
Increase (Decrease) in Short Term Debt  21,945      8,600    (14,600)
Proceeds from Common Stock Issued         -        10,289     16,208
Repurchase of Common Stock             (29,626)    (3,909)      -
Redemption of Preferred Stock          (24,500)   (24,500)    (5,469)
Dividends Declared on Preferred Stock  (14,627)   (16,716)   (17,405)
Dividends Declared on Common Stock     (81,088)   (75,829)   (67,259)
Other-Net                                9,067     12,330      8,584 
Net Cash (Used) Provided by Financing 
 Activities                             (7,414)   (77,827)    14,151 
Net Increase (Decrease) in Cash and 
 Temporary Investments                     577    (68,521)    27,988
Cash and Temporary Investments, 
 beginning of year                       5,114     73,635     45,647
Cash and Temporary Investments,       
 end of year                          $  5,691   $  5,114   $ 73,635

Supplemental Schedule of Payments:
Interest                              $ 61,160   $ 62,855   $ 52,765
Income taxes                          $ 30,769   $ 23,374   $ 19,565
Noncash Financing Activities:
Common Stock issued under stock plans $    137   $  7,652   $ 14,088


The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements. 
<PAGE>
CONSOLIDATED BALANCE SHEET      
(Thousands of Dollars)
                                                   December 31,
                                                1995          1994
Assets
Electric Utility Plant:
In Service:
  Production                                 $1,187,169    $1,151,661 
  Transmission                                  366,242       357,389
  Distribution                                  691,830       659,619
  General                                       183,935       180,204
Total In Service                              2,429,176     2,348,873
Less Accumulated Depreciation                   794,479       725,999
Net                                           1,634,697     1,622,874
Construction Work in Progress                   119,270       110,078
Land Held for Future Use                          6,941         6,941
Leased Property-Net                              40,878        42,030
Electric Utility Plant-Net                    1,801,786     1,781,923

Investments and Nonutility Property:
Investment in Leveraged Leases                   78,959        78,216
Nuclear Decommissioning Trust Fund               61,802        52,004
Nonutility Property and Equipment-Net            22,743        18,163
Other Investments and Funds                      52,780        28,940
Total Investments and Nonutility Property       216,284       177,323

Current Assets:
Cash and Temporary Investments                    5,691         5,114
Accounts Receivable:
  Utility Service                                66,099        54,554
  Miscellaneous                                  17,477        14,067
  Allowance for Doubtful Accounts                (3,300)       (3,300)
Unbilled Revenues                                41,515        32,070
Fuel (at average cost)                           25,459        28,030
Materials and Supplies (at average cost)         25,434        27,823
Working Funds                                    14,421        14,475
Deferred Energy Costs                            31,434        10,999
Deferred Income Taxes                              -           12,264
Prepaid Excise Tax                               10,753         5,287
Other                                            13,339         6,596
Total Current Assets                            248,322       207,979

Deferred Debits:
Unrecovered Purchased Power Costs                99,817       115,538
Recoverable Future Federal Income Taxes          85,858        85,854
Unrecovered State Excise Taxes                   64,274        73,834
Unamortized Debt Costs                           39,004        38,184
Other Regulatory Assets                          54,568        47,055
Other                                            10,983        17,865
Total Deferred Debits                           354,504       378,330

Total Assets                                 $2,620,896    $2,545,555

The accompanying Notes to Consolidated Financial Statements are an 
integral part of these statements.
<PAGE>
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
                                                   December 31,
                                                1995           1994

Liabilities and Capitalization
Capitalization:
Common Shareholders' Equity:
Common Stock, no par value; 75,000,000 
 shares authorized; issued and outstanding: 
 1995 - 52,531,878; 1994 - 54,155,245        $  563,436     $  593,475
Retained Earnings                               249,741        249,181
Total Common Shareholders' Equity               813,177        842,656
Preferred Stock: 
 Not Subject to Mandatory Redemption             40,000         40,000
 Subject to Mandatory Redemption                114,750        149,250
Long Term Debt                                  829,856        778,288
Total Capitalization (excluding current                      
  portion)                                    1,797,783      1,810,194

Current Liabilities:
Preferred Stock Redemption Requirement           22,250         12,250
Long Term Debt                                   65,247          1,000
Short Term Debt                                  30,545          8,600
Accounts Payable                                 60,858         66,080
Taxes Accrued                                     3,450         10,409
Interest Accrued                                 20,315         19,168
Dividends Declared                               23,490         24,681
Accrued Employee Separation Costs                 7,488         26,600
Deferred Income Taxes                             2,569           -   
Other                                            20,554         19,813
Total Current Liabilities                       256,766        188,601

Deferred Credits and Other Liabilities:
Deferred Income Taxes                           425,875        412,574
Deferred Investment Tax Credits                  49,112         51,646
Capital Lease Obligations                        40,227         41,111
Other                                            51,133         41,429
Total Deferred Credits and Other Liabilities    566,347        546,760

Commitments and Contingencies (Note 10)  

Total Liabilities and Capitalization         $2,620,896     $2,545,555
         

The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.










CONSOLIDATED STATEMENT OF CHANGES IN             
COMMON SHAREHOLDERS' EQUITY
(Thousands of Dollars)
                                                Common      Retained
                                  Shares        Stock       Earnings

Balance, December 31, 1992      52,198,624     $549,147     $242,768
Common Stock issued              1,308,162       30,296
Net Income                                                    95,297
Capital stock expense of
 subsidiary                                                     (169)
Dividends on Common Stock                                    (81,347)
Balance, December 31, 1993      53,506,786      579,443      256,549
Common Stock issued                870,159       17,941
Common Stock repurchased          (221,700)      (3,909)            
Net Income                                                    76,113 
Dividends on Common Stock                                    (83,481)
Balance, December 31, 1994      54,155,245      593,475      249,181
Common Stock issued*                 1,633         (413)              
Common Stock repurchased        (1,625,000)     (29,626)            
Net Income                                                    81,768  
Dividends on Common Stock                                    (81,208)
Balance, December 31, 1995      52,531,878     $563,436     $249,741

*Included in Common Stock issued are amounts associated with
adjustments made for employee stock plans.
      

The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements. 
<PAGE>
Notes to Consolidated Financial Statements
Note 1. SIGNIFICANT ACCOUNTING POLICIES

Organization - Atlantic Energy, Inc. (the Company, AEI or parent)
is the parent of Atlantic City Electric Company (ACE) and
Atlantic Energy Enterprises, Inc. (AEE), which are wholly-owned
subsidiaries.  ACE is a public utility primarily engaged in the
generation, transmission, distribution and sale of electric
energy.  ACE's service territory encompasses approximately 2,700
square miles within the southern one-third of New Jersey with the
majority of customers being residential and commercial.  ACE,
with its wholly-owned subsidiary that operates certain generating
facilities, is the principal subsidiary within the consolidated
group.  On January 1, 1995, AEI transferred direct ownership of
its existing nonutility companies to AEE.  AEE is a holding
company which is responsible for the management of the
investments in the nonutility companies consisting of:  Atlantic
Generation, Inc. (AGI), Atlantic Southern Properties, Inc. (ASP),
ATE Investment, Inc. (ATE), Atlantic Thermal Systems, Inc. (ATS), 
CoastalComm, Inc. (CCI) and Atlantic Energy Technology, Inc.
(AET).  AGI and its wholly-owned subsidiaries are engaged in the
development, acquisition, ownership and operation of cogeneration
power projects.  AGI's activities, through its subsidiaries, are
represented by partnership interests in three cogeneration
facilities located in New Jersey and New York.  ASP owns and
manages a commercial office and warehouse facility located in
southern New Jersey.  ATE provides funds management and financing
to affiliates and manages a portfolio of investments in leveraged
leases for equipment used in the airline and shipping industries. 
ATS and its wholly-owned subsidiaries are engaged in the
development and operation of thermal heating and cooling systems. 
AET is presently concluding the affairs of its subsidiary, which
is its sole investment and only activity.  CCI was formed in
November 1995 and manages investments in telecommunication
technology.  AEE also has a 50% equity interest in a limited
liability company which provides energy management services,
including natural gas supply, transportation and marketing.  

Principles of Consolidation - The consolidated financial
statements include the accounts of the Company and its
subsidiaries.  All significant intercompany accounts and
transactions have been eliminated in consolidation.  ACE and AEE
consolidate their respective subsidiaries.  Ownership interests
in other entities, between 20% and 50%, where control is not
evident, are accounted for using the equity method by recognizing
a proportionate share of the results of operations of that
investment.  The results of operations of the nonutility
companies are not significant to the results of the Company and
are classified under Other Income in the Consolidated Statement
of Income. 






Regulation - The accounting policies and rates of service for ACE
are subject to the regulations of the New Jersey Board of Public
Utilities (BPU) and in certain respects to the Federal Energy
Regulatory Commission (FERC).  ACE follows generally accepted
accounting principles (GAAP) and financial reporting requirements
employed by all industries as specified by the Financial
Accounting Standards Board (FASB) and the Securities and Exchange
Commission (SEC).  However, accounting for rate regulated
industries may depart from GAAP applied by other industries as
permitted by Statement of Financial Accounting Standards No. 71
(SFAS No. 71).  SFAS No. 71 provides guidance on circumstances
where the economic effect of a regulator's decision warrants
different applications of GAAP as a result of the ratemaking
process.  In setting rates, a regulator may provide recovery of
an incurred cost in a year or years other than the year the cost
is incurred.  As permitted by SFAS No. 71, costs ordered by a
regulator to be deferred or capitalized for future recovery are
recorded as a regulatory asset because the regulator's rate
action provides reasonable assurance of future economic benefits
attributable to these costs.  In a non-rate regulated industry,
such costs may be charged to expense in the year incurred.  SFAS
No. 71 further specifies that a regulatory liability is recorded
when a regulator orders a refund to customers of revenues
previously collected, or when existing rates provide for recovery
of future costs not yet incurred.  Such treatment is not afforded
to non-rate regulated companies.  When collection of regulatory
assets or relief of regulatory liabilities is no longer probable,
the assets and liabilities are applied to income in the year that
the assessment is made.  Specific regulatory assets and
liabilities that have been recorded are discussed elsewhere in
the notes to the consolidated financial statements.

Electric Operating Revenues - Revenues are recognized when
electric energy services are rendered, and include estimates for
amounts unbilled at the end of the year for energy used by
customers subsequent to the last bill rendered for the calendar
year.

Nuclear Fuel - Fuel costs associated with ACE's participation in
jointly-owned nuclear generating stations, including spent
nuclear fuel disposal costs, are charged to Energy expense based
on the units of thermal energy produced.

Electric Utility Plant - Property is stated at original cost. 
Generally, the plant is subject to a first mortgage lien.  The
cost of property additions, including replacement of units of
property and betterments, is capitalized.  Included in certain
property additions is an Allowance for Funds Used During
Construction (AFDC), which is defined in the applicable
regulatory system of accounts as the cost, during the period of
construction, of borrowed funds used for construction purposes
and a reasonable rate on other funds when so used.  AFDC has been
calculated using a semi-annually compounded rate of 8.25% since
August 1, 1993.  The AFDC rate was 8.95% prior to this date. 
Property and equipment of the nonutility companies are not
significant.  

Depreciation - ACE provides for straight-line depreciation based
on:  transmission and distribution property - estimated remaining
life;  nuclear property - remaining life of the related plant
operating license in existence at the time of the last base rate
case;  other depreciable property - estimated average service
life.  The overall composite rate of depreciation was 3.3% for
the last three years.  Accumulated depreciation is charged with
the cost of depreciable property retired together with removal
costs less salvage and other recoveries.  Depreciation for the
nonutility companies is not significant.

Nuclear Plant Decommissioning Reserve -  A reserve for
decommissioning costs is presented as a component of accumulated
depreciation and amounted to $60.9 million and $51.1 million at
December 31, 1995 and 1994, respectively.  

The SEC has questioned certain accounting practices employed by
the electric utility industry concerning decommissioning costs
for nuclear generating facilities.  The FASB is currently
reviewing this issue within the broad context of removal costs
relative to all industries.  At this time, the Company cannot
predict what future accounting practices may be required by the
FASB and SEC concerning this issue, or the impact on future
financial statements, that any new accounting practices may have.
  
Deferred Energy Costs - As approved by the BPU, ACE has a
Levelized Energy Clause (LEC) through which energy and energy-
related costs (energy) are charged to customers.  LEC rates are
based on projected energy costs and prior period underrecoveries
or overrecoveries.  Generally, energy costs are recovered through
levelized rates over the period of projection, which is usually a
12-month period.  In any period, the actual amount of LEC
revenues recovered from customers may be greater or less than the
recoverable amount of energy costs incurred in that period. 
Energy expense is adjusted to match the associated LEC revenues. 
Any underrecovery (an asset representing energy costs incurred
that are to be collected from customers) or overrecovery (a
liability representing previously collected energy costs to be
returned to customers) of costs is deferred on the Consolidated
Balance Sheet as Deferred Energy Costs.  These deferrals are
recognized in the Consolidated Statement of Income as Energy
expense during the period in which they are subsequently included
in the LEC.  ACE may elect to forgo recovery of certain amounts
of otherwise recoverable energy costs.  Such amounts are
expensed.

Income Taxes - Deferred Federal and state income taxes are
provided on all significant temporary differences between book
bases and tax bases of assets and liabilities, transactions that
reflect taxable income in a year different than book income, and
tax carryforwards.  Investment tax credits previously used for
income tax purposes have been deferred on the Consolidated
Balance Sheet and are recognized in book income over the life of
the related property.  The Company and its subsidiaries file a
consolidated Federal income tax return.  Income taxes are
allocated to each of the companies within the consolidated group
based on the separate return method.

Earnings Per Common Share - This is computed based upon the
weighted average number of common shares outstanding during the
year.  Common stock equivalents exist but are not included in the
computation of earnings per share because they are currently
antidilutive.

Financial Instruments - A number of items within Current Assets
and Current Liabilities on the Consolidated Balance Sheet are
considered to be financial instruments because they are cash or
are to be settled in cash.  Due to their short term nature, the
carrying values of these items approximate their fair market
values.  Accounts Receivable - Utility Service and Unbilled
Revenues are subject to concentration of credit risk because they
pertain to utility service conducted within a fixed geographic
region.  Investments in Leveraged Leases are subject to
concentration of credit risk because they are exclusive to a
small number of parties within two industries.  The Company has
recourse to the affected assets under lease.  These leased assets
are of general use within their respective industries.

Other - Debt premium, discount and expense of ACE are amortized
over the life of the related debt.  Temporary investments
considered as cash equivalents for Consolidated Statement of Cash
Flows purposes represent purchases of highly liquid debt
instruments maturing in three months or less.  ACE's weighted
daily average interest rate on short term debt was 6.3% for 1995
and 4.4% for 1994.  AEI's weighted daily average interest rate on
its short term debt was 6.3% for 1995.  There was no short term
debt outstanding for AEI in 1994.

The preparation of financial statements in conformity with GAAP
requires management at times to make certain judgments, estimates
and assumptions that affect amounts and matters reported at the
year end dates and for the annual periods presented.  Actual
results could differ from those estimates.  Any change in the
judgments, estimates and assumptions used, which in management's
opinion would have a significant effect on the financial
statements, will be reported when management becomes aware of
such changes.
<PAGE>
New Accounting Standards - The FASB issued two new statements in
1995 - Statement No. 121 "Accounting for the Impairment of Long-
Lived Assets and for Long-Lived Assets to be Disposed Of" and
Statement No. 123 "Accounting for Stock-Based Compensation". 
Both statements are effective for the Company in 1996.  Statement
No. 121 primarily concerns accounting for the impairment and
disposal of property, plant and equipment.  Statement No. 123
permits a fair value-based method to account for stock-based
compensation as an alternative to the intrinsic value-based
method that is currently permitted.  The Company currently
employs stock-based compensation which has not had a material
impact on the financial statements.  Should the Company elect to
continue to use the intrinsic value-based method to account for
stock-based compensation, the statement requires, if material,
certain disclosures as if the fair value-based method was used. 
The Company has not yet fully assessed the impacts on its
financial statements of the requirements of these new accounting
standards. 

Certain prior year amounts have been reclassified to conform to
the current year reporting of these items.
<PAGE>
NOTE 2.  INCOME TAXES
The components of Federal income tax expense for the years ended
December 31 are as follows:
                                      
(000)                                  1995        1994        1993   
Current                             $ 20,483    $ 19,729    $ 25,349
Deferred                              25,993      17,414      20,247
Investment Tax Credits Recognized    
 on Leveraged Leases                     (28)         -          (12)
Total Federal Income Tax Expense      46,448      37,143      45,584
Less Amounts in Other Income             572      (5,386)        307
Federal Income Taxes in 
 Operating Expenses                 $ 45,876    $ 42,529    $ 45,277

A reconciliation of the expected Federal income taxes compared to the
reported Federal income tax expense computed by applying the statutory
rate for the years ended December 31 follows:
                                       1995        1994        1993
Statutory Federal Income Tax Rate       35%         35%         35%
(000)
Income Tax Computed at the           
 Statutory Rate                     $ 49,995    $ 45,490    $ 55,400
Plant Basis Differences                1,307         (27)     (5,171)
Amortization of Investment Tax
 Credits                              (2,562)     (2,534)     (2,546)
Tax Adjustments                         (897)     (4,097)     (2,071)
Other-Net                             (1,395)     (1,689)        (28)
Total Federal Income Tax Expense    $ 46,448    $ 37,143    $ 45,584
Effective Federal Income Tax Rate       33%         29%         30%

State income tax expense is not significant.

Items comprising deferred tax balances as of December 31 are as
follow: 
(000)                                 1995         1994    

Deferred Tax Liabilities:
Plant Basis Differences             $316,834     $304,476
Leveraged Leases                      71,180       61,409
Unrecovered Purchased Power Costs     28,209       33,557
State Excise Taxes                    22,527       25,842 
Other                                 32,825       24,732
  Total Deferred Tax Liabilities     471,575      450,016
Deferred Tax Assets:
Deferred Investment Tax Credits       26,511       27,879
Employee Separation Costs              2,621        6,932
Other                                 13,999       15,245
  Total Deferred Tax Assets           43,131       50,056
Total Deferred Taxes-Net            $428,444     $399,960

At December 31, 1995 and 1994, deferred tax assets exist for
cumulative state income tax net operating loss (NOL's)
carryforwards.  Valuation allowances of virtually the same
amounts have been recorded.  The effects of the state NOL's and
associated valuation allowances are not material to consolidated
results of operations and financial position.  At December 31,
1995, unexpired state NOL's amount to approximately $72 million,
with expiration dates from 1996 through 2002.

At December 31, 1995 there was an estimated remaining Federal
Alternative Minimum Tax (AMT) credit of approximately $7 million. 
The AMT credit is available for an indefinite carryforward period
against future Federal income tax payable, to the extent that the
regular Federal income tax payable exceeds future AMT payable. 
The AMT is included with the tax effects of leveraged leases. 

Deferred tax costs associated with additional deferred tax
liabilities resulting from a prior year accounting change are
recorded on the Consolidated Balance Sheet as Recoverable Future
Federal Income Taxes.  This recognition is given for the probable
amount of revenue to be collected from ratepayers for these
additional taxes to be paid in future years.

NOTE 3.  RATE MATTERS OF ACE 

Energy Clause Proceedings

              Changes in Levelized Energy Clause Rates
                            1993 - 1995
                              
                    Amount            Amount             
     Date         Requested          Granted            Date
     Filed        (millions)        (millions)        Effective

     3/93            $14.2             $10.9            10/93
     2/94             63.0              55.0             7/94
     4/95             37.0              37.0             7/95

ACE's Levelized Energy Clause (LEC) is subject to annual review
by the BPU.

In March 1993, ACE filed a petition with the BPU requesting a
$14.2 million increase in LEC revenues for the June 1, 1993
through May 31, 1994 LEC period.  Effective for service rendered
on and after October 1, 1993, the BPU approved an increase of
$10.9 million.  The request was reduced primarily to return to
customers an additional 25%, or $3.8 million, of a $15.5 million
litigation settlement with the operator of the Peach Bottom
Atomic Power Station.     

On February 8, 1994, ACE filed a petition with the BPU requesting
an increase in LEC revenues of $63 million for the period June 1,
1994 through May 31, 1995.  The increase was primarily due to the
additional costs incurred from two new independent power
producers (IPPs) scheduled to begin commercial operation during
the 1994/1995 LEC period.  The requested amount was reduced by
$84 million as a result of the utilization of $56 million of
current base rate revenues associated with a utility power
purchase contract expiring in May 1994 and the Southern New
Jersey Economic Initiative (SNJEI), an ACE initiative that
forgoes the recovery of $28 million of energy costs that ACE will
incur during the LEC period.  On November 30, 1994, the BPU
rendered its final decision approving the continuation of a
provisional LEC rate increase of $55 million that had been in
effect since July 26, 1994.       
   
On April 17, 1995, ACE filed a petition with the BPU requesting a
$37 million increase in LEC revenues for the period June 1, 1995
through May 31, 1996.  This filing represents the first that
includes a full year of costs for capacity and energy with all
four of the IPPs with which ACE is under contract.  The requested
amount had been reduced by ACE from $67.6 million by forgoing $10
million in LEC revenues under the SNJEI and deferring $20.6
million of LEC costs that ACE will incur during the 1995/1996 LEC
period for recovery in a future LEC period.  Effective July 7,
1995, the BPU approved a provisional increase of $37 million
effective for service rendered on and after July 7, 1995.  On
November 15, 1995, the Administrative Law Judge (ALJ) recommended
that the provisional rates be made final.  On December 1, 1995,
the Ratepayer Advocate, the BPU Staff and ACE agreed to a
stipulation recommending that the ALJ's findings be accepted by
the BPU.  A final decision is expected from the BPU by the end of
March 1996.

Other Rate Proceedings

In November 1993, ACE filed a petition with the BPU requesting
that hotel-casino customers be permitted to take service under
rate schedules offered to all other commercial and industrial
customers.  On June 23, 1994, the BPU approved the request. 
Prior to BPU approval, hotel-casino customers were served under
the Hotel Casino Service rate schedule, the highest rate for
service of all ACE's service classes.  Effective July 1, 1994,
all hotel-casino customers began taking service under a general
service rate schedule.  The effect of this change was not
material to the results of operations. 
   
On September 14, 1994, the BPU issued an order supporting the
investigation of the double recovery of capacity costs from
nonutility generation projects.  This issue relates to the
Ratepayer Advocate's allegation that ACE, along with other New
Jersey electric utility companies, is recovering cogeneration
capacity costs concurrently in base rates and LEC rates.  The
order confirmed the establishment of a generic proceeding to
review the nonutility capacity cost recovery methodology and
ordered that the matter be reviewed in a two phase proceeding. 
The scope of the issues to be resolved during the first phase of
the proceeding include:  1) the determination of the existence,
or lack of existence, of the double recovery as a result of the
traditional LEC pass-through of nonutility generation capacity
costs;  2) the quantification of any double recovery found to
exist for each utility for the relevant periods;  3) a
determination of an appropriate remedy or adjustment if double
recovery is found to occur and the periods of time over which an
adjustment would be applicable.  Following the conclusion of the
first phase of the proceeding, the BPU, in the second phase, will
render a final decision regarding the specific findings of the
Office of Administrative Law and address the broader issues
relating to the appropriate prospective purchase power capacity
cost recovery methods.  In September 1995, the Ratepayer Advocate
filed testimony that claims ACE's overrecovery of capacity costs
for the four-year period June 1991 through May 1995 is $46
million.  The Ratepayer Advocate also filed testimony supporting
similar claims with respect to other New Jersey electric
utilities.  In December 1995, ACE and the other electric
utilities filed testimony rebutting the Ratepayer Advocate's
claims.  Litigation is expected to continue in 1996; the BPU's
final decision is not expected until the latter part of 1996.  At
this time, ACE cannot predict the outcome of this proceeding and
cannot estimate the impact that the double recovery issue may
have on future rates.

NOTE 4.  RETIREMENT BENEFITS

Pension

ACE has a noncontributory defined benefit pension plan covering
substantially all of its employees and those of its wholly-owned
subsidiary.  Benefits are based on an employee's years of service
and average final pay.  ACE's policy is to fund pension costs
within the guidelines of the minimum required by the Employee
Retirement Income Security Act and the maximum allowable as a tax
deduction.  Each company is allocated its participative share of
plan costs and contributions.

Net periodic pension costs include:
(000)                                  1995      1994      1993
Service cost-benefits earned  
 during the period                  $  6,363  $  6,871  $  7,196
Interest cost on projected benefit                                
 obligation                           14,794    15,390    16,016
Actual return on plan assets         (44,067)     (860)  (23,200)    
Other-net                             28,379   (16,885)    5,496  
Net periodic pension costs          $  5,469  $  4,516  $  5,508  


Of these costs, $3.0 million were charged to operating expense in both
1995 and 1994 and $5.2 million in 1993.  The remaining costs, which
are associated with construction labor, were charged to the cost of
new utility plant.  Actual return on plan assets and other-net for
1995 primarily reflect the favorable market conditions from the
investment of plan assets and expected returns versus the unfavorable
market conditions in 1994.    
<PAGE>
A reconciliation of the funded status of the plan as of December 31 is
as follows:

(000)                                  1995          1994      
Fair value of plan assets            $212,000      $190,200     
Projected benefit obligation          213,470       206,742     
Plan assets less than           
 projected benefit obligation          (1,470)      (16,542)    
Unrecognized net transition asset      (1,550)       (1,722)   
Unrecognized prior service cost           282           306
Unrecognized net loss                  10,006        24,106    
Prepaid pension cost                 $  7,268      $  6,148     
Accumulated benefit obligation:
Vested benefits                      $169,044      $166,602     
Nonvested benefits                      3,413           485     
Total                                $172,457      $167,087         

At December 31, 1995, approximately 65% of plan assets were invested
in equity securities, 21% in fixed income securities and 14% in other
investments.  The assumed rates used in determining the actuarial
present value of the projected benefit obligation at December 31 were
as follows:
                                         1995       1994
Weighted average discount                7.0%       7.5%
Anticipated increase in compensation     3.5%       3.5%

The assumed long term rate of return on plan assets was 8.5% for both
1995 and 1994.

Other Postretirement Benefits 

ACE and its subsidiary provide certain health care and life insurance
benefits for retired employees and their eligible dependents. 
Substantially all employees may become eligible for these benefits if
they reach retirement age while working for the companies.  Benefits
are provided through insurance companies and other plan providers
whose premiums and related plan costs are based on the benefits paid
during the year.  ACE has a tax qualified trust to fund these
benefits.  Each company is allocated its participative share of plan
costs and contributions.  

Net periodic other postretirement benefit costs include:
(000)                                  1995        1994        1993  
Service cost-benefits attributed to 
 service during the period           $ 2,891     $ 3,817     $ 3,045
Interest cost on accumulated 
 postretirement benefits obligation    8,107       8,450       7,133
Actual return on plan assets          (1,437)        100        (255) 
Amortization of unrecognized 
 transition obligation                 3,893       3,893       3,893
Other-net                                404        (700)       (711)
Net periodic other postretirement 
  cost                               $13,858     $15,560     $13,105  



These costs were allocated as follows:
(millions)                                 1995     1994     1993
Operating expense                          $5.0     $5.6     $3.3
New utility plant-associated with   
 construction labor                          .6       .2      1.7
Regulatory asset                            8.3      9.8      8.1

The regulatory asset represents the amount of cost recognized in
excess of the amount of cost currently recovered in rates.  These
excess costs are deferred as authorized by an accounting order of the
BPU pending future recovery through rates.   

A reconciliation of the funded status of the plan as of December 31 is
as follows:
(000)                                        1995         1994   
Accumulated benefits obligation:
Retirees                                  $ 64,516     $ 43,265 
Fully eligible active plan participants      6,954       18,010 
Other active plan participants              33,649       60,588 
Total accumulated benefits obligation      105,119      121,863 
Less fair value of plan assets              16,500       14,700 
Accumulated benefits obligation in      
 excess of plan assets                      88,619      107,163 
Unrecognized net loss                      (15,335)     (19,223)
Unamortized unrecognized transition 
 obligation                                (47,057)     (70,075)
Accrued other postretirement benefits      
 cost obligation                          $ 26,227     $ 17,865

The accumulated benefit obligation for retirees and other active plan
participants for 1995 reflect the impact of ACE's workforce reduction
program and a lower discount rate effective in 1995.  The unamortized
unrecognized transition obligation for 1995 was reduced by certain
changes to the plan.

At December 31, 1995, approximately 80% of plan assets were invested
in fixed income securities and 20% in other investments.

The assumed health care costs trend rate for 1996 is 9% and is assumed
to evenly decline to an ultimate constant rate of 5% in the year 2001
and thereafter.  If the assumed health care costs trend rate was
increased by 1% in each future year, the aggregate service and
interest costs of the 1995 net periodic benefits cost would increase
by $1.8 million, and the accumulated postretirement benefits
obligation at December 31, 1995 would increase by $12.1 million.  The
weighted average discount rate assumed in determining the accumulated
benefits obligation was 7% for 1995 and 7.5% for 1994.  The assumed
long term return rate on plan assets was 7% for both 1995 and 1994. 

<PAGE>
NOTE 5.  JOINTLY-OWNED GENERATING STATIONS

ACE owns jointly with other utilities several electric production
facilities.  ACE is responsible for its pro-rata share of the costs of
construction, operation and maintenance of each facility.

The amounts shown represent ACE's share of each facility at, or for
the year ending, December 31, including AFDC as appropriate.           
                                                                       
                                       Peach                  Hope
              Keystone   Conemaugh     Bottom      Salem      Creek   
Energy Source   Coal        Coal      Nuclear     Nuclear    Nuclear
Company's Share
 (%/MWs)      2.47/42.3  3.83/65.4   7.51/157.0  7.41/164.0  5.00/52.0

Electric Plant in Service (000):
1995           $12,719    $35,371     $128,398    $214,306   $239,499
1994            11,293     26,607      125,003     206,804    238,980

Accumulated Depreciation (000):
1995           $ 3,277    $ 6,445     $ 58,870    $ 84,611   $ 60,998
1994             3,180      6,237       55,190      79,898     53,746

Construction Work in Progress (000):
1995           $   442    $   873     $ 11,056    $ 11,198   $    655
1994             1,216      2,649       11,002       8,727        387

Operations and Maintenance Expenses (including fuel)(000):
1995           $ 5,143    $ 7,252     $ 29,647    $ 28,306   $ 10,360
1994             5,085      7,211       29,530      27,731     10,471 
1993             5,323      6,855       31,479      27,021      9,764

Working Funds (000):
1995           $    44    $    69     $  4,505    $  5,782   $  1,919
1994                44         69        5,051       5,199      2,013

Generation (MWHr):
1995           285,899    451,211    1,232,921     334,572    352,316 
1994           257,561    419,313    1,214,776     836,725    355,390
1993           293,876    416,263    1,043,485     840,043    440,118

ACE provides financing during the construction period for its share of
the jointly-owned facilities and includes its share of direct
operations and maintenance expenses in the Consolidated Statement of
Income.  Additionally, ACE provides an amount of working funds to the
operators of the facilities to fund operational needs.  

The decrease in Salem's generation is due to both units being taken
out of service in May and June 1995, respectively, by its operator
Public Service Electric and Gas Company, pending review and resolution
of certain equipment and management issues. (See Note 10 for further
information).
          <PAGE>
NOTE 6.  NONUTILITY COMPANIES

Principal assets of each of the subsidiary companies of AEE at
December 31, 1995 are:  AGI - investments of approximately $30.6
million in cogeneration facilities;  ASP - commercial real estate site
with a net book value of $10.1 million;  ATE - leveraged lease
investments of $79.0 million;  ATS - construction costs in thermal
heating and cooling projects of $11.9 million.  In November 1995, CCI
was formed to invest in telecommunication systems.  In December 1995,
CCI invested $5.2 million in such business opportunities.  Other
financial information regarding the subsidiary companies is as
follows:

                       Net Worth           Net Income (Loss)  
Company              1995      1994     1995     1994     1993
(000)
AGI                $26,082   $23,610   $2,513   $2,959   $4,459 
ASP                  2,334     3,175     (841)  (1,956)    (347)
ATE                  9,399     9,449      (50)     266     (777)
ATS                  2,187     2,577     (213)    (327)     -
CCI                  5,258       -        -        -        -  
       
AGI's results in each year primarily reflect the equity in earnings of
cogeneration facilities in which AGI has an ownership interest. 

ASP's results in each year reflect vacancy in its commercial site due
to generally poor market conditions in commercial real estate. 
Additionally, 1994 included a net after tax write-down of the carrying
value of the commercial site of $1.7 million.  

ATE's 1995 results reflect increased interest expense associated with
its revolving credit and term loan agreement.  1993 results reflect
adjustments in income taxes.     

ATS's results for 1995 and 1994 reflect administrative and general
costs in the development of operations, while construction of heating
and cooling systems are underway.  Operating expenses were offset in
part in 1995 by revenues generated from the operation and maintenance
of heating and cooling facilities.

AEI and AEE parent-only operations, excluding equity in the results of
subsidiary companies, generally reflect administrative and general 
expenses in the management of their respective subsidiaries. AEI's
results were losses of $1.6 million in 1995, $543 thousand in 1994 and
$183 thousand in 1993.  AEI's 1995 results reflect interest charges
associated with a line of credit established to fund repurchases of
common stock and certain affiliate capital needs.  AEE's 1995 results 
were a loss of $2.4 million.









NOTE 7.  CUMULATIVE PREFERRED STOCK OF ACE

ACE has authorized 799,979 shares of Cumulative Preferred Stock, $100
Par Value, two million shares of No Par Preferred Stock and three
million shares of Preference Stock, No Par Value.  Information
relating to outstanding shares at December 31 is shown in the table
below.
                                                                       
                                                             Current
                                                             Optional
         Par            1995                    1994        Redemption 
Series  Value     Shares     (000)        Shares     (000)    Price    
Not Subject to Mandatory Redemption:
4%       $100      77,000   $ 7,700        77,000   $ 7,700   $105.50
4.10%     100      72,000     7,200        72,000     7,200    101.00
4.35%     100      15,000     1,500        15,000     1,500    101.00
4.35%     100      36,000     3,600        36,000     3,600    101.00
4.75%     100      50,000     5,000        50,000     5,000    101.00
5%        100      50,000     5,000        50,000     5,000    100.00
7.52%     100     100,000    10,000       100,000    10,000    101.88
Total                       $40,000                 $40,000
Subject to Mandatory Redemption:
$8.25     None     50,000  $  5,000        55,000  $  5,500    104.45
$8.53     None    120,000    12,000       360,000    36,000    101.00
$8.20     None    500,000    50,000       500,000    50,000       -
$7.80     None    700,000    70,000       700,000    70,000       -
Total                       137,000                 161,500
Less portion due within
 one year                    22,250                  12,250
Total                      $114,750                $149,250            
                                                                    

Cumulative Preferred Stock Not Subject to Mandatory Redemption is
redeemable solely at the option of ACE.

On November 1 of each year, 2,500 shares of the $8.25 No Par Preferred
Stock must be redeemed through the operation of a sinking fund at a
redemption price of $100 per share.  ACE may redeem not more than an
additional 2,500 shares on any sinking fund date without premium.  ACE
redeemed 5,000 shares in each of the years 1995 and 1994.

On November 1 of each year, 120,000 shares of the $8.53 No Par
Preferred Stock must be redeemed through the operation of a sinking
fund at a redemption price of $100 per share.  At the option of ACE,
not more than an additional 120,000 shares may be redeemed on any
sinking fund date without premium.  ACE redeemed 240,000 shares in
each of the years 1995 and 1994.  ACE redeemed the remainder of this
series at a price of $101.00 in February 1996.  

Beginning August 1, 1996 and annually thereafter, 100,000 shares of
the $8.20 No Par Preferred Stock must be redeemed through the
operation of a sinking fund at a redemption price of $100 per share. 
At the option of ACE, not more than an additional 100,000 shares may
be redeemed on any sinking fund date without premium.  This series is
not refundable prior to August 1, 2000.    

Beginning May 1, 2001 and annually through 2005, 115,000 shares of
$7.80 No Par Preferred Stock must be redeemed through the operation of
a sinking fund at a redemption price of $100 per share.  On May 1,
2006, the remaining shares outstanding must be redeemed at $100 per
share.  ACE has the option to redeem up to an additional 115,000
shares without premium on each May 1 through 2005.  This series is not
refundable prior to May 1, 2006.  

At December 31, 1995, the minimum annual sinking fund requirements of
the Cumulative Preferred Stock Subject to Mandatory Redemption for the
next five years are $22.25 million in 1996 and $10.25 million in each
of the years 1997 through 2000.

Cumulative Preferred Stock of ACE is not widely held and trades
infrequently.  The estimated aggregate fair market value of ACE's
outstanding Cumulative Preferred Stock at December 31, 1995 and 1994
was approximately $172 million and $185 million, respectively.  The
fair market value has been determined using market information
available from actual trades of similar instruments of companies with
similar credit quality and rate.
<PAGE>
NOTE 8.  LONG TERM DEBT                                                
                                Maturity         December 31,   
Series                                 Date         1995       1994   
(000)
5-1/8% First Mortgage Bonds          2/1/1996    $  9,980   $  9,980
Medium Term Notes Series B (6.28%)   1998          56,000     56,000
Medium Term Notes Series A (7.52%)   1999          30,000     30,000
Medium Term Notes Series B (6.83%)   2000          46,000     46,000
Medium Term Notes Series C (6.86%)   2001          40,000        -
7-1/2% First Mortgage Bonds          4/1/2002      20,000     20,000
Medium Term Notes Series C (7.02%)   2002          30,000        -
Medium Term Notes Series B (7.18%)   2003          20,000     20,000
7-3/4% First Mortgage Bonds          6/1/2003      29,976     29,976
Medium Term Notes Series A (7.98%)   2004          30,000     30,000
Medium Term Notes Series B (7.125%)  2004          28,000     28,000
Medium Term Notes Series C (7.15%)   2004           9,000        -
Medium Term Notes Series B (6.45%)   2005          40,000     40,000
6-3/8% Pollution Control            12/1/2006       2,500      2,500
Medium Term Notes Series C (7.15%)   2007           1,000        -
Medium Term Notes Series B (6.76%)   2008          50,000     50,000
Medium Term Notes Series C (7.25%)   2010           1,000        -
10-1/2% Pollution Control Series B   7/15/2012        -          850
6-5/8% First Mortgage Bonds          8/1/2013      75,000     75,000
7-3/8% Pollution Control Series A    4/15/2014     18,200     18,200
Medium Term Notes Series C (7.63%)   2014           7,000        -
Medium Term Notes Series C (7.68%)   2015          15,000        -
Medium Term Notes Series C (7.68%)   2016           2,000        -
8-1/4% Pollution Control Series A    7/15/2017      4,400      4,400
9-1/4% First Mortgage Bonds         10/1/2019         -       53,857
6.80% Pollution Control Series A     3/1/2021      38,865     38,865
7%    First Mortgage Bonds           9/1/2023      75,000     75,000
5.60% Pollution Control Series A    11/1/2025       4,000      4,000
7%    First Mortgage Bonds           8/1/2028      75,000     75,000
6.15% Pollution Control Series A     6/1/2029      23,150     23,150
7.20% Pollution Control Series A    11/1/2029      25,000     25,000
7%    Pollution Control Series B    11/1/2029       6,500      6,500
 Total                                            812,571    762,278  
Debentures:
5-1/4%                               2/1/1996       2,267      2,267
7-1/4%                               5/1/1998       2,619      2,619
Total                                               4,886      4,886  
Unamortized Premium and Discount-Net               (2,854)    (3,876)
Total Long Term Debt of ACE                       814,603    763,288
Long Term Debt of AEI                              34,500        -     
Long Term Debt of ATE                              33,500     16,000
Long Term Debt of ATS                              12,500        -
Less Portion Due within One Year                   65,247      1,000
                                                 $829,856   $778,288  

Medium Term Notes have varying maturity dates and are shown with the
weighted average interest rate of the related issues within the year
of maturity.




In 1995, ACE redeemed its 10-1/2% Pollution Control Bonds Series B due
7/15/2012 and the remaining outstanding principal amount of its 9-1/4%
First Mortgage Bonds due 10/1/2019.  The aggregate cost of these
redemptions was $2.6 million, net of related Federal income taxes.

Sinking fund deposits are required for retirement of First Mortgage
Bonds, 6-3/8% Pollution Control Series due 2006 annually beginning
December 1, 1997 in amounts sufficient to redeem $75 thousand
principal amount.  Sinking fund deposits are also required for
retirement of 7-1/4% Debentures annually on May 1 through 1997 in
amounts sufficient to redeem $100 thousand principal amount.  ACE may,
at its option, redeem an additional $100 thousand annually.  Through
December 31, 1995, ACE acquired and cancelled $81 thousand principal
amount of the 7-1/4% Debentures, which will be used to satisfy its
requirements for 1996.  Certain series of First Mortgage Bonds contain
provisions for deposits of cash or certification of bondable property
currently amounting to $100 thousand, which ACE may elect to satisfy
through property additions.  For the next five years, the annual
amount of scheduled maturities and sinking fund requirements of ACE's
long term debt are $12.266 million in 1996, $175 thousand in 1997,
$58.575 million in 1998, $30.075 million in 1999 and $46.075 million
in 2000.  

ACE's long term debt securities are not widely held and generally
trade infrequently.  The estimated aggregate fair market value of
ACE's outstanding long term debt at December 31, 1995 and 1994 was
$851 million and $693 million, respectively.  The fair market value
has been determined based on quoted market prices for the same or
similar debt issues or on debt instruments of companies with similar
credit quality, coupon rates and maturities.

In September 1995, AEI established a $75 million revolving credit and
term loan facility.  The revolver is comprised of a 364-day senior
revolving credit facility in the amount of $35 million and a three-
year senior revolving credit facility in the amount of $40 million. 
Interest rates on borrowings will be based on senior debt ratings and
on the borrowing option selected by the Company.  As of December 31,
1995, AEI had $34.5 million outstanding.  This facility can be used to
fund further acquisitions of Company Common Stock and for other
general corporate purposes.

Long term debt of ATE consists of $15 million of 7.44% Senior Notes
due 1999.  The estimated fair market value of these Notes at December
31, 1995 and 1994 was approximately $16 million and $14 million,
respectively, based on debt instruments of companies with similar
credit quality, coupon rates and maturities.  Also, ATE has a
revolving credit and term loan agreement which provides for borrowings
of up to $25 million during successive revolving credit and term loan
periods through June 1996.  There were $18.5 million in borrowings
outstanding under this agreement at December 31, 1995.  Commitment
fees on the unused credit line were not significant.  

On December 13, 1995, ATS through a partnership arrangement borrowed
from the New Jersey Economic Development Authority (EDA) $12.5 million
from the proceeds of bonds issued by the EDA.  The bonds have an
initial interest rate of 3.70%.  Availability of the borrowed funds
for their intended use and the ultimate term of the borrowing are
subject to certain conditions.  Satisfaction of these conditions and
use of the funds are expected in 1996.

NOTE 9.  COMMON SHAREHOLDERS' EQUITY

In addition to public offerings, Common Stock may be issued through
the Dividend Reinvestment and Stock Purchase Plan (DRP), ACE benefit
plans (ACE plans) and the Equity Incentive Plan (EIP).  The number of
shares of Common Stock issued (forfeited), and the number of shares
reserved for issuance at December 31, 1995, were as follows:
                  1995        1994          1993       Reserved
DRP                 -        699,493     1,300,129     723,975
ACE Plans        (7,601)      (5,046)        8,033     148,639
EIP               9,234      175,712          -        615,054
Total             1,633      870,159     1,308,162

Eligible participants of the EIP are officers, general managers and
nonemployee directors of the Company and its subsidiaries.  Under the
EIP, nonemployee director participants are entitled to receive a grant
of 1,000 shares of restricted stock.  Restrictions on these grants
expire over a five-year period.  Employee participants may be awarded
shares of restricted Common Stock, stock options and other Common
Stock-based awards.  Actual awards of restricted shares are based on
attainment of certain Company performance criteria within a three-year
period.  Restrictions lapse upon actual award at the end of the three-
year performance period.  Shares not awarded are forfeited.  Dividends
earned on restricted stock issued through the EIP are invested in
additional restricted stock under the EIP which is subject to the same
award criteria. 

Activity in the EIP, initiated in April 1994, was as follows:
                                                                       
                            Restricted                   Option
                              Shares        Options       Price
Issued/Granted                175,712       167,300       21.125
Balance, December 31, 1994    175,712       167,300
Issued/Granted                 24,435         6,387       21.125
Forfeited                      (7,587)       (6,700)      21.125
Balance, December 31, 1995    192,560       166,987 

The 1995 restricted shares granted include 7,614 shares purchased on
the open market from reinvestment of dividends on EIP shares
outstanding.

Stock options granted are nonqualified and are exercisable 3 years
after but within 10 years from the date of grant.  Stock options are
priced at an amount at least equal to 100% of the fair market value of
the related Common Stock at the date of grant.  No options were
eligible to be exercised in 1995 or 1994.

The Company has a program to reacquire up to three million shares of
the Company's Common Stock outstanding.  There is no schedule or
specific share price target associated with the reacquisitions.  The
authorized number of shares is not to be affected.  During 1995, the
Company reacquired and cancelled 1,625,000 shares for a total cost of
$29.6 million with prices ranging from $17.625 to $18.875 per share. 
At December 31, 1995, the Company has reacquired and cancelled
1,846,700 shares of its common stock at a total cost of $33.5 million.

NOTE 10.  COMMITMENTS AND CONTINGENCIES

Construction Program

Cash construction expenditures for 1996 are estimated to be
approximately $192 million.  

Insurance Programs

Nuclear
ACE is a member of certain insurance programs that provide coverage
for decontamination and property damage to members' nuclear generating
plants.  Facilities at the Peach Bottom, Salem and Hope Creek stations
are insured against property damage losses up to $2.75 billion per
site under these programs.

In addition, ACE is a member of an insurance program which provides
coverage for the cost of replacement power during prolonged outages of
nuclear units caused by certain specific conditions.  The insurer for
nuclear extra expense insurance provides stated value coverage for
replacement power costs incurred in the event of an outage at a
nuclear unit resulting from physical damage to the nuclear unit.  The
stated value coverage is subject to a deductible period of the first
21 weeks of any outage.  Limitations of coverage include, but are not
limited to, outages 1) not resulting from physical damage to the unit,
2) resulting from any government mandated shutdown of the unit, 3)
resulting from any gradual deterioration, corrosion, wear and tear,
etc. of the unit, 4) resulting from any intentional acts committed by
an insured and 5) resulting from certain war risk conditions.  Under
the property and replacement power insurance programs, ACE could be
assessed retrospective premiums in the event the insurers' losses
exceed their reserves.  As of December 31, 1995, the maximum amount of
retrospective premiums ACE could be assessed for losses during the
current policy year was $6.4 million under these programs.

The Price-Anderson provisions of the Atomic Energy Act of 1954, as
amended by the Price-Anderson Amendments Act of 1988, govern liability
and indemnification for nuclear incidents.  All nuclear facilities
could be assessed, after exhaustion of private insurance, up to
$79.275 million each reactor per incident, payable at $10 million per
year.  Based on its ownership share of nuclear facilities, ACE could
be assessed up to an aggregate of $27.6 million per incident.  This
amount would be payable at an aggregate of $3.48 million per year, per
incident.

Other

ACE's comprehensive general liability insurance provides pollution
liability coverage, subject to certain terms and limitations for
environmental costs incurred in the event of bodily injury or property
damage resulting from the discharge or release of pollutants into or
upon the land, atmosphere or water.  Limitations of coverage include
any pollution liability 1) resulting subsequent to the disposal of
such pollutants, 2) resulting from the operation of a storage facility
of such pollutants, 3) resulting in the formation of acid rain, 4)
caused to property owned by an insured and 5) resulting from any
intentional acts committed by an insured.

Nuclear Plant Decommissioning 

ACE has a trust to fund the future costs of decommissioning each of
the five nuclear units in which it has an ownership interest.  The
current annual funding amount, as authorized by the BPU, totals $6.4
million and is provided for in rates charged to customers.  The
funding amount is based on estimates of the future cost of
decommissioning each of the units, the dates that decommissioning
activities are expected to begin and return to be earned by the assets
of the fund.  The present value of ACE's nuclear decommissioning
obligation, based on costs adopted by the BPU in 1991 and restated in
1995 dollars, is $157 million.  Decommissioning activities as approved
by the BPU were expected to begin in 2006 and continue through 2032. 
ACE will seek to adjust these estimates and the level of rates
collected from customers in future BPU proceedings to reflect changes
in decommissioning cost estimates and the expected levels of inflation
and interest to be earned by the assets in the trust.  The total
estimated value of the trust at December 31, 1995, inclusive of the
present value of future funding, based on current annual funding
amounts and expected decommissioning dates approved by the BPU, is
approximately $131 million, without earnings on or appreciation of the
fund assets.  As of December 31, 1995, the market value of the trust
approximated the book value.  In accordance with BPU requirements,
updated site specific studies are underway.  Amounts to be recognized
and recovered in rates based on the updated studies are not presently
determinable.

Purchased Capacity and Energy Arrangements

ACE arranges with various providers of bulk energy to obtain
sufficient supplies of energy to satisfy current and future energy
requirements of the company.  Arrangements may be for generating
capacity and associated energy or for energy only.  Terms of the
arrangements vary in length to enable ACE to optimally manage its
supply portfolio in response to changing near and long term market
conditions.  At December 31, 1995, ACE has contracted for 707
megawatts (MW's) of purchased capacity with terms remaining of 3 to 29
years.  Additionally, ACE has contracted for capacity of 125 MW's
commencing in 1998 for 2 years and for 175 MW's commencing in 1999 for
10 years.   Information regarding these arrangements relative to ACE
was as follows:
                               1995        1994        1993     
As a % of Capacity (year end)     30%         29%         23%  
As a % of Generation              52%         48%         46%  
Capacity charges (millions)   $190.6      $130.9      $110.8  
Energy charges (millions)     $135.4      $128.6       $98.3
    
Amounts for purchased capacity are shown on the Consolidated Statement
of Income as Purchased Capacity.  Of these amounts, charges of certain
nonutility providers are recoverable through the LEC, which amounted
to $162.7 million, $77.0 million and $30.2 million in 1995, 1994 and
1993, respectively.  Future purchases of energy and payments for
purchased capacity and energy under contracts with remaining terms in
excess of one year from December 31, 1995 generally are contingent
upon provider performance and availability, and as such are not
presently determinable.
Environmental Matters

The provisions of Title IV of the Clean Air Act Amendments of 1990
(CAAA) will require, among other things, phased reductions of sulfur
dioxide (SO2) emissions by 10 million tons per year, a limit on SO2
emissions nationwide by the year 2000 and reductions in emissions of
nitrogen oxides (NOx) by approximately 2 million tons per year.  ACE's
wholly-owned B.L. England Units 1 and 2 and its jointly-owned
Conemaugh Station Units 1 and 2 are in compliance with Phase I
requirements as the result of recent installation of scrubbers at each
station.  All of ACE's other fossil-fuel steam generating units are
affected by Phase II (2000) of the CAAA.  A compliance plan for these
units initially estimates capital expenditures of approximately $10
million in 1996 through 2000.  The jointly-owned Keystone Station is
impacted by the SO2 and NOx provisions of Title IV of the CAAA during
Phase II.  The Keystone owners plan to primarily rely on emission
allowances to comply with the CAAA through the year 2000.  

Other

ACE is a 7.41% owner of the Salem Nuclear Generating Station (Salem)
operated by Public Service Electric & Gas Company (PS). Salem Units 1
and 2 were taken out of service on May 16, 1995 and June 7, 1995,
respectively.  Unit 2 is expected to return to service in the third
quarter of 1996.  A thorough assessment of the equipment and
management issues that have affected the operation of the unit and
station are being resolved and necessary corrections are being made to
assure safe and reliable operation over the long term.  Unit 1 is
undergoing extended testing of its steam generation equipment and its
return has been delayed to an indefinite period.  ACE's expenses
associated with restart activities totalled $2.6 million for 1995 and
are estimated to be $5.6 million for 1996.  The additional incremental
cost of replacement power during the outages is approximately $1.4
million per month.

ACE is a 5% owner in the Hope Creek Nuclear Generating Station (Hope
Creek) also operated by PS.  Hope Creek went into a scheduled
refueling and maintenance outage on November 11, 1995 which has been
extended to correct maintenance and performance problems.  The unit is
expected to return to service in March 1996.  The incremental
replacement power costs associated with the Hope Creek outage is
approximately $400 thousand per month.  

ACE is subject to a performance standard for its five jointly-owned
nuclear units.  This standard is used by the BPU in determining
recovery of replacement energy costs.  The standard establishes a
target aggregate capacity factor within a zone of reasonable
performance to be achieved by the units.  Underperformance results in
penalties.  Penalties incurred are not permitted to be recovered from
customers and are charged against income.  For 1995, ACE recorded $845
thousand after tax for a performance penalty because the aggregate
capacity factor of ACE's nuclear units was below the reasonable
performance zone as a result of the Salem outage noted above. 
   
In December 1994, ACE recorded the costs of an employee separation
program in the amount of $17.3 million, net of tax of $9.3 million, or
$.32 in earnings per share.  This program was initiated so that ACE
could be better positioned for the more competitive environment within
the electric industry.  The balance of the accrued separation costs on
the Consolidated Balance Sheet at December 31, 1995 is $7.5 million
compared to $26.6 million at December 31, 1994.  ACE expects payments
in settlement of this obligation to be substantially completed by the
end of 1996.

The Energy Policy Act of 1992 permits the Federal government to assess
investor-owned electric utilities that have ownership interests in
nuclear generating facilities.  The assessment funds the
decontamination and decommissioning of three Federally operated
nuclear enrichment facilities.  Based on its ownership in five nuclear
generating units, ACE has a liability of $6.0 million and $6.6 million
at December 31, 1995 and 1994, respectively, for its obligation to be
paid over the next 12 years.  ACE has an associated regulatory asset
of $6.4 million and $7.2 million at December 31, 1995 and 1994,
respectively.  Amounts are currently being recovered in rates for this
liability and the regulatory asset is concurrently being amortized to
expense based on the annual assessment billed by the Federal
government.

In March 1995, FERC issued a Notice of Proposed Rulemaking regarding
several key electric utility industry issues such as transmission
access, transmission pricing and recovery guidelines for stranded
costs stemming from wholesale transactions.  The focus of the proposal
is to establish policies that will provide a structure to facilitate
more competitive wholesale electric power markets.  What is being
proposed is a departure from the existing regulatory framework.  FERC
is considering comments on the proposal submitted by ACE and other
members of the industry, as well as other interested parties. 
Associated with the FERC proposal are structural initiatives by the
BPU concerning New Jersey electric regulation and by the regional
power pool in which ACE participates regarding bulk power transmission
and generation dispatch within the region.  At this time, the Company
cannot predict the outcomes of these sweeping initiatives and the
impacts on the Company that may ensue.  The Company is taking an
active role in the development of these issues.
<PAGE>
Note 11.  REGULATORY ASSETS AND LIABILITIES

Costs incurred by ACE that have been permitted by the BPU to be
deferred for recovery in rates in more than one year, or for which
future recovery is probable, are recorded as regulatory assets.
Regulatory assets are amortized to expense over the period of
recovery.  Total regulatory assets at December 31 are as follows:  
                                                                       
                                                          Remaining   
                                                          Recover
(000)                                1995         1994       Period*
Recoverable Future Federal   
 Income Taxes(see Note 2)          $ 85,858     $ 85,854       (A)
Unrecovered Purchased Power Costs:
 Capacity Costs                      80,598       95,878       5 years 
 Contract Renegotiation Costs        19,219       19,660      19 years
Unrecovered State Excise Taxes       64,274       73,834       7 years
Unamortized Debt Costs-Refundings    33,110       32,227    1-29 years
Deferred Energy Costs(see Note 1)    31,434       10,999       (B)
Other Regulatory Assets:
 Postretirement Benefits Other
  Than Pensions (see Note 4)         26,227       17,865       (A)
 Asbestos Removal Costs               9,356        9,625      34 years 
 Decommissioning/Decontaminating       
  Federally-owned Nuclear Units      
  (See Note 10)                       6,404        7,231      13 years 
 Other                               12,581       14,379               
                                   $369,061     $367,552          
*From December 31, 1995
(A)  Pending future recovery
(B)  Recovered over annual LEC period


Unrecovered Purchased Power Capacity Costs represent deferrals of
prior capacity costs then in excess of levelized revenues associated
with a certain long term capacity arrangement.  Levelized revenues
have since been greater than costs, permitting the deferred costs to
be amortized to expense.  Contract Renegotiation Costs were incurred
through renegotiation of a long term capacity and energy contract with
a certain independent power producer.  Unrecovered State Excise Taxes
represent additional amounts paid as a result of prior legislative
changes in the computation of state excise taxes.  Unamortized Debt
Costs associated with debt reacquired by refundings are amortized over
the life of the related new debt.  Asbestos Removal Costs were
incurred to remove asbestos insulation from a wholly-owned generating
station.  Within Other are certain amounts being recovered over a
period of two to six years.
 
No regulatory liabilities existed at December 31, 1995 and 1994.
<PAGE>
NOTE 12.  LEASES

ACE leases from others various types of property and equipment for use
in its operations.  Certain of these lease agreements are capital
leases consisting of the following at December 31:

(000)                                1995       1994
Production plant                   $ 9,097    $13,521
Less accumulated amortization        6,810      9,707
Net                                  2,287      3,814
Nuclear fuel                        38,591     38,216
Leased property-net                $40,878    $42,030

ACE has a contractual obligation to obtain nuclear fuel for the Salem,
Hope Creek and Peach Bottom stations.  The asset and related
obligation for the leased fuel are reduced as the fuel is burned and
are increased as additional fuel purchases are made.  No commitments
for future payments beyond satisfaction of the outstanding obligation
exist.  Operating expenses for 1995, 1994 and 1993 include leased
nuclear fuel costs of $11.2 million, $14.1 million and $13.9 million,
respectively, and rentals and lease payments for all other capital and
operating leases of $3.9 million, $5.3 million and $4.8 million,
respectively.  Future minimum rental payments for all noncancellable
lease agreements are not significant to ACE's operations.

Rental charges of nonutility companies are not significant. 

ATE is the lessor in five leveraged lease transactions consisting of
three aircraft and two containerships with total respective costs of
approximately $168 million and $76 million.  Remaining lease terms for
all leases approximate 15 to 16 years.  The Company's equity
participation in the leases range from 22% to 32%.  Funding of the
investment in the leveraged lease transactions is comprised of equity
participation by ATE and financing provided by third parties as long
term debt without recourse to ATE.  The lease transactions provide
collateral for such third parties, including a security interest in
the leased equipment.  Net investment in leveraged leases at December
31 was as follows:
                                          1995         1994    
Rentals receivable (net of principal     
 and interest on nonrecourse debt)     $ 50,955     $ 51,012    
Estimated residual values                53,435       53,435    
Unearned and deferred income            (25,431)     (26,232)    
Investment in leveraged leases           78,959       78,215    
Deferred taxes arising from leveraged   
 leases                                 (71,064)     (61,409)   
       
Net investment in leveraged leases     $  7,895     $ 16,806      




<PAGE>
NOTE 13.  QUARTERLY FINANCIAL RESULTS (UNAUDITED)

Quarterly financial data, reflecting all adjustments necessary in the
opinion of management for a fair presentation of such amounts, are as
follows:                                                               
                                                          Dividends
         Operating    Operating      Net      Earnings      Paid      
Quarter  Revenues       Income      Income    Per Share   Per Share 
1995       (000)        (000)       (000) 
1st      $218,626     $ 27,584     $11,469     $ .21       $ .385
2nd       206,232       27,771      10,568       .20         .385  
3rd       302,685       66,482      48,745       .93         .385  
4th       225,594       26,700      10,986       .21         .385

Annual   $953,137     $148,537     $81,768     $1.55       $1.54    
1994                       
1st      $232,098     $ 39,712     $22,862     $ .43       $ .385
2nd       205,822       30,427      16,798       .31         .385
3rd       272,708       58,431      46,323       .85         .385
4th       202,410       24,969      (9,871)     (.18)        .385

Annual   $913,039     $153,540     $76,113     $1.41       $1.54


Individual quarters may not add to the total due to rounding, and the
effect on earnings per share of changing average number of common
shares outstanding.  

Third quarter results generally exceed those of other quarters due to
increased sales and higher residential rates for ACE.

Net income in 1994 includes special charges aggregating $20.4 million,
after tax of $10.9 million, or $.37 per share, recorded in Other
Income during the fourth quarter of 1994.  These special charges
consisted of costs of a workforce reduction, write-off of certain
deferred costs and a write-down in carrying value of certain property.

<PAGE>
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 

     Information for this item concerning Directors of the
Company is set forth in the section entitled "Nominees for
Election" on page 3 of the Company's Notice of Annual Meeting of
Shareholders and definitive Proxy Statement, which is
incorporated by reference.  The information required by Item 10
of Form 10-K with respect to the executive officers of the
Company and the directors of ACE is, pursuant to Instruction 3 to
Item 401(b) of Regulation S-K, set forth in Part I of this Form
10-K under the heading "Executive Officers".

ITEM 11   EXECUTIVE COMPENSATION

     Information for this item with respect to the amounts paid
to the five most highly compensated executive officers of the
Company and ACE, is set forth in the section entitled "Table 1-
Summary Compensation Table" on page 14 of the Company's Notice of
Annual Meeting of Shareholders and definitive Proxy Statement,
which is incorporated herein by reference.  The cash compensation
paid to 13 executive officers of ACE, as a group, in 1995 was
$2,531,032.

ITEM 12   SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
          MANAGEMENT

     The information required by this item as to compliance with
Section 16(a) of the Exchange Act is contained in the section
captioned "Stock Ownership of Directors and Officers"  on page 6
of the Company's Notice of Annual Meeting of Shareholders and
definitive Proxy Statement, which is incorporated herein by
reference.

ITEM 13   CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

     Information for this item is set forth in the section
entitled "Personnel & Benefits Committee Interlocks and Insider
Participation" on page 14 of the Company's Notice of Annual
Meeting of Shareholders and definitive Proxy Statement, which is
incorporated herein by reference.

PART IV

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

Exhibits:  See Exhibit Index attached.
Financial Statements and Supplementary Schedules:  The following 
information for Atlantic Energy, Inc. is filed as part of this
report.
<PAGE>
Management's Discussion and Analysis of 
Financial Condition and Results of Operation           Page  46
Consolidated Statement of Income for the three 
years ended December 31, 1995                          Page  60
Consolidated Statement of Cash Flows for 
the three years ended December 31, 1995                Page  61 
Consolidated Balance Sheet - December 31, 1995 
and December 31, 1994                                  Page  62 
Consolidated Statement of Changes in Common
Shareholders' Equity                                                   Page  64 

Notes to Consolidated Financial Statements             Page  65 
Supplementary information regarding selected 
quarterly financial data (Unaudited) (Note 13 to 
Financial Statements)                                  Page  89 
Independent Auditors' Report                           Page  59 
Report of Management                                   Page  57 

     The following financial information, financial statements
and notes to financial statements for ACE are filed herewith as
Exhibit 28(a) and are incorporated by reference herein:

   Management's Discussion and Analysis of Financial Condition
and Results of Operation; Consolidated Statement of Income for
the three years ended December 31, 1995; Consolidated Statement
of Cash Flows for the three years ended December 31, 1995;
Consolidated Balance Sheet-December 31, 1995 and December 31,
1994; Consolidated Statement of Changes in Common Shareholder's
Equity; Notes to Consolidated Financial Statements; Independent
Auditors' Report.

     All other financial schedules are included in the Financial
Statements and Notes to Financial Statements of the Company and
ACE.

Reports on Form 8-K:

   Current Reports on Form 8-K were filed, dated October 19,
1995 and December 14, 1995 relating to the shutdown, and
subsequent events, of Salem Units 1 and 2 on May 16, 1995 and
June 7, 1995, respectively.   <PAGE>
                               SIGNATURES

     Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized, who also signed in the capacity
indicated.

                           ATLANTIC ENERGY, INC.
                      ATLANTIC CITY ELECTRIC COMPANY


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

Date: March 19, 1996                    By:  /s/ J. L. Jacobs     
                                                 J. L. Jacobs

Title: President and Chief Executive Officer 
       and Director of Atlantic Energy, Inc. and Chairman,
       Chief Executive Officer and Director of
       Atlantic City Electric Company

Date:  March 19, 1996                   By:  /s/ M. J. Barron     
                                                 M. J. Barron

Title: Vice President and Chief Financial Officer of Atlantic
       Energy, Inc. and Senior Vice President and Chief
       Financial Officer of Atlantic City Electric Company

DIRECTORS OF ATLANTIC ENERGY, INC.:
Jos. Michael Galvin, Jr.*               Kathleen MacDonnell*
Gerald A. Hale*                         Richard B. McGlynn*
Matthew Holden, Jr.*                    Bernard J. Morgan*
Cyrus H. Holley*                        Harold J. Raveche*
E. Douglas Huggard*

A MAJORITY OF DIRECTORS OF ATLANTIC CITY ELECTRIC COMPANY:
Michael J. Chesser*                     James E. Franklin II*
Meredith I. Harlacher, Jr.*             Henry K. Levari, Jr.*
M. T. Powell *


Date:   March 19, 1996                  *By:  /s/ M. J. Barron    
                                                  M. J. Barron    
                                              Attorney-in-Fact

<PAGE>
                            EXHIBIT INDEX

3a  Restated Certificate of Incorporation of Atlantic Energy,
Inc. (File No. 1-9760, Form 10-Q for quarter ended September 30,
1987-Exhibit 4(a)); Certificate of Amendment to restated
Certificate of Incorporation of Atlantic Energy, Inc. dated April
15, 1992.  File No. 33-53511, Form S-8 dated May 6, 1994-Exhibit
No. 3(ii).

3b  By-Laws of Atlantic Energy, Inc. as amended August 8, 1991
(File No. 1-9760, Form 10-K for year ended December 31, 1991-
Exhibit No. 3b);  By-Laws of Atlantic Energy, Inc. as amended
July 13, 1995 (File No. 1-9760, Form 10-Q for the quarter ended
June 30, 1995 - Exhibit 3b(1).

3c  Agreement of Merger between Atlantic City Electric Company
and South Jersey Power & Light Company filed June 30, 1949, and
Amendments through May 3, 1991 (File No. 2-71312-Exhibit No.
3(a); File No. 1-3559, Form 10-Q for quarter ended June 30, 1982-
Exhibit No. 3(b); Form 10-Q for quarter ended March 31, 1985-
Exhibit No. 3(a); Form 10-Q for quarter ended March 31, 1987-
Exhibit No. 3(a): Form 8-K dated October 12, 1988-Exhibit No.
3(a); Form 10-K for fiscal year ended December 31, 1990-Exhibit
No. 3c; and Form 10-Q for quarter ended September 30, 1991-
Exhibit No. 3c). 

3d  By-Laws of Atlantic City Electric Company, as amended April
24, 1989 (File No. 1-3559, Form 10-Q for the quarter ended
September 31, 1989-Exhibit No. 3).

4a  Purchase Agreement, dated as of December 1, 1977, with
respect to $8.25 No Par Preferred Stock of Atlantic City Electric
Company (File No. 2-60966-Exhibit No. 2(d)).

4b  Mortgage and Deed of Trust, dated January 15, 1937, between
Atlantic City Electric Company and The Bank of New York (formerly
Irving Trust Company) and Supplemental Indentures through
November 1, 1994 (File No. 2-66280-Exhibit No. 2(b); File No. 1-
3559, Form 10-K for year ended December 31, 1980-Exhibit No.
4(d); Form 10-Q for quarter ended June 30, 1981-Exhibit No. 4(a);
Form 10-K for year ended December 31, 1983-Exhibit No. 4(d); Form
10-Q for quarter ended March 31, 1984-Exhibit No. 4(a); Form 10-Q
for quarter ended June 30, 1984-Exhibit 4(a); Form 10-Q for
quarter ended September 30, 1985-Exhibit 4; Form 10-Q for quarter
ended March 31, 1986-Exhibit No. 4; Form 10-K for year ended
December 31, 1987-Exhibit No. 4(d); Form 10-Q for quarter ended
September 30, 1989-Exhibit No. 4(a); Form 10-K for year ended
December 31, 1990-Exhibit No. 4(c); File No. 33-49279-Exhibit No.
4(b); File No. 1-3559, Form 10-Q for the quarter ended September
30, 1993 - Exhibits 4(a) & 4(b); Form 10-K for the year ended
December 31, 1993 - Exhibit 4c(i); File no. 1-3559, Form 10-Q for
the quarter ended June 30, 1994 - Exhibit 4(a); File No. 1-3559,
Form 10-Q for the quarter ended September 30, 1994 - Exhibit
4(a); Form 10-K for year ended December 31, 1994-Exhibit 4(c)(1).
<PAGE>
4e  Agreement dated as of February 1, 1966, between Atlantic City
Electric Company and Fidelity Union Trust Company and Supplement
dated as of May 1, 1968. (File No. 1-3559, Form 8-K dated
March 7, 1966-Exhibit 13(b)(2); Form 8-K dated June 6, 1968-
Exhibit No. 13(b)(1)).

4f(1)  Revolving Credit and Term Loan Agreement dated as of May
24, 1988 by and between ATE Investment, Inc. and The Bank of New
York (File No.1-9760, Form 10-K for year ended December 31, 1988-
Exhibit No. 4g(1)).

4f(2)  Support Agreement dated as of May 24, 1988 between
Atlantic Energy, Inc. and ATE Investment, Inc. (File No. 1-9760,
Form 10-K for year ended December 31, 1988-Exhibit No. 4g(2)).

4f(3)  Letter Agreement dated as of May 24, 1988 between Atlantic
Energy, Inc. and The Bank of New York (File No. 1-9760, Form 10-K
for year ended December 31, 1988-Exhibit No. 4g(3)).

4f(4)  Amendment No. 1 dated as of February 22, 1989 to Revolving
Credit and Term Loan Agreement dated as of May 24, 1988 by and
between ATE Investment, Inc. and The Bank of New York (File No.
1-9760, Form 10-K for the fiscal year ended December 31, 1988).

4f(5) Amendment No. 2 dated as of June 1, 1991, to Revolving
Credit and Term Loan Agreement dated as of May 24, 1988 by and
between ATE Investment, Inc. and The Bank of New York (File No.
1-9760, Form 10-K for year ended December 31, 1991-Exhibit No.
4f(5)).

4f(6) Revolving Credit Agreements dated as of September 28, 1995
by and among Atlantic Energy, Inc., The Bank of New York, as
agent, and Lender party thereto, filed herewith.

10a(1) Atlantic Energy, Inc. Directors Deferred Compensation Plan
revised as of February 4, 1988 (File No. 1-9760, Form 10-K for
year ended December 31, 1988-Exhibit No. 10a(1)).

10a(2) Description of amendment to the Deferred Compensation Plan
for Directors effective December 10, 1992 (File No. 1-9760, Form
10-K for year ended December 31, 1992-Exhibit No. 10a(1)). 

10a(3) Deferred Compensation Plan for Employees of Atlantic
Energy, Inc. and Participating Subsidiaries (File No. 1-9760, 
Form 10-K for year ended December 31, 1988-Exhibit No. 10a(2)).

10a(4)  Description of amendment to Deferred Compensation Plan 
for Employees of Atlantic Energy, Inc. and Participating
Subsidiaries effective December 10, 1992 (File No. 1-9760, Form
10-K for year ended December 31, 1992-Exhibit No. 10a(2)). 

10a(5) Supplemental Executive Retirement Plan for Officers of
Atlantic City Electric Company, as amended effective March 1,
1990 (File No. 1-9760, Form 10-K for year ended December 31,
1989-Exhibit No. 10a(4)).

10a(5)1  Supplemental Executive Retirement Plan - II for Officers
of Atlantic City Electric effective September 8, 1995, filed
herewith. 

10a(6)  Description of amendment to Supplemental Executive
Retirement Plan effective December 10, 1992 (File No. 2-9760,
Form 10-K for year ended December 31, 1992-Exhibit 10a(3)).

10a(6)1  Supplemental Executive Retirement Plan for Officers of
Atlantic City Electric Company, amendment No. 1995-1, filed
herewith.

10a(7)  Executive Medical Expense Reimbursement Plan for Officers
of Atlantic City Electric Company (File No. 1-3559, Form 10-K for
year ended December 31, 1985-Exhibit No. 10a(5)).

10a(8)  Copy of Management Annual Incentive Plan of Atlantic
Energy, Inc. and its subsidiaries, effective January 1, 1992
(File No. 1-9760, Form 10-K for year ended December 31, 1991-
Exhibit No. 10a(5)).

10a(9)  Copy of Atlantic Electric Excess Benefit Retirement
Income Program, as amended, effective as of August 2, 1990 (File
No. 1-3559, Form 10-K for year ended December 31, 1991-Exhibit
No. 10a(6)).

10a(10)  Description of amendment to the Excess Benefit
Retirement Income Program effective December 10, 1992 (File No.
1-9760, Form 10-K for year ended December 31, 1992-Exhibit
10a(6)).

10a(10)1  Atlantic City Electric Company Excess Benefit
Retirement Income Program, Amendment No. 1995-1, filed herewith.

10a(11)  Agreement, effective as of February 1, 1990, between
Atlantic City Electric Company and E. Douglas Huggard (File No.
1-9760, Form 10-K for year ended December 31, 1989-Exhibit No.
10a(8)).

10a(12)  Agreement entered February 11, 1993 between Atlantic
City Electric Company and E. Douglas Huggard (File No. 1-9760,
Form 10-K for year ended December 31, 1992-Exhibit No. 10a(7)).

10a(13)  Copy of Atlantic City Electric Company Long-Term
Performance Incentive Plan, as amended effective November 1, 1990
(File No. 1-3559, Form 10-K for year ended December 31, 1991-
Exhibit No. 10a(8)).

10a(14)  Atlantic Energy, Inc. Retirement Plan for Directors, as
amended effective November 13, 1991 (File No. 1-9760, Form 10-K
for year ended December 31, 1991-Exhibit No. 10a(9)).

10a(14)1  Atlantic Energy, Inc. Retirement Plan for Directors,
Amendment No. 1995-1, filed herewith.

10a(15)  Copy of Atlantic Energy, Inc. Restricted Stock Plan for
Non-employee Directors, effective January 1, 1991 (File No. 1-
9760, Form 10-K for year ended December 31, 1991-Exhibit No.
10a(10)).

10a(16)  Agreement dated February 11, 1993 between Atlantic City
Electric Company and Jerrold L. Jacobs (File No. 1-3559, Form 10-
K for the year ended December 31, 1994 - Exhibit No. 10a(16)).


10a(16)1  Agreement dated August 10, 1995 between Atlantic
Energy, Inc. and Jerrold L. Jacobs, as amended, filed herewith.

10a(17)  Agreement dated February 10, 1994 between Atlantic City
Electric Company and Meredith I. Harlacher, Jr. (File No. 1`-
3559, Form 10-K for the year ended December 31, 1993 - Exhibit
No. 10a(17)). 

10a(17)1  Agreement dated August 10, 1995 between Atlantic
Energy, Inc. and Meredith I. Harlacher, Jr. as amended, filed
herewith.

10a(18)  Agreement dated February 10, 1994 between Atlantic City
Electric Company and Henry K. Levari, Jr. (File No. 1-3559, Form
10-K for the year ended December 31, 1993 - Exhibit No. 10a(18)).

10a(19)  Agreement dated February 10, 1994 between Atlantic City
Electric Company and J. G. Salomone, Amendment to Agreement
Termination and Release Agreement dated  January 31, 1995 between
Atlantic City Electric Company and J. G. Salomone (File No. 1-
3559, Form 10-K for the year ended December 31, 1993 - Exhibit
No. 10a(19)); Amendment to Agreement Termination and Release
Agreement between Atlantic City Electric Company and J. G.
Salomone (File No. 1-3559, Form 10-K for the year ended December
31, 1994 - Exhibit No. 10a(19)). 

10a(20)  Agreement dated January 10, 1994 between Atlantic City
Electric Company and Michael Chesser (File No. 1-3559, Form 10-K
for the year ended December 31, 1993 - Exhibit No. 10a(20)). 

10a(20)1  Agreement dated August 10, 1995 between Atlantic
Energy, Inc. and Michael J. Chesser, as amended, filed herewith.

10a(21)  Agreement dated October 1, 1994 between Atlantic City
Electric Company and James E. Franklin II (File No. 1-3559, Form
10-K for year ended December 31, 1994-Exhibit 10a(23).

10a(22)  Atlantic Energy, Inc. Equity Incentive Plan (File No.
33-53511, Form S-8 filed May 6, 1994-Exhibit 10.)

10a(23)  Agreement dated August 10, 1995 between Atlantic Energy,
Inc. and Marilyn T. Powell, as amended, filed herewith.

10a(24)  Agreement dated August 10, 1995 between Atlantic Energy,
Inc. and Scott B. Ungerer, as amended, filed herewith.

10b(1)  Agreement as to ownership as tenants in common of the
Salem Nuclear Generating Station Units 1, 2, and 3, dated
November 24, 1971, and of Supplements, dated as of September 1,
1975, and as of January 26, 1977 (File No. 2-43137-Exhibit No.    
5(p); File No. 2-60966-Exhibit No. 5(m); and File No. 2-58430-
Exhibit No. 5(o)).

10b(2)  Agreement as to ownership as tenants in common of the
Peach Bottom Atomic Power Station Units 2 and 3, dated November
24, 1971 and of Supplements dated as of September 1, 1975 and as
of January 26, 1977 (File No. 2-43137-Exhibit No. 5(o); File No.
2-60966-Exhibit No. 5(j); File No. 2-58430-Exhibit No. 5(m)).

10b(3)  Owners Agreement, dated April 28, 1977 between Atlantic
City Electric Company and Public Service Electric & Gas Company
for the Hope Creek Generating Station Units No. 1 and 2 (File No.
2-60966-Exhibit No. 5(v)).
10b(3-1)  Amendment to Owners Agreement for Hope Creek Generating
Station, dated as of December 23, 1981, between Atlantic City
Electric Company and Public Service Electric & Gas Company (File
No. 1-3559, Form 10-K for year ended December 31, 1983-Exhibit
No. 10b(3-2)).

10b(4)  Pennsylvania-New Jersey-Maryland Interconnection
Agreement, dated September 26, 1956 between Public Service
Electric & Gas Company, Philadelphia Electric Company,
Pennsylvania Power & Light Company, Baltimore Gas & Electric
Company, Jersey Central Power & Light Company, Metropolitan
Edison Company, Pennsylvania Electric Company, Potomac Electric
Power Company and supplemental agreements through June 15, 1977
(File No. 1-3559, Form 10-K for year ended December 31, 1981-
Exhibit No. 10(p)).

10b(5)  Pennsylvania-New Jersey-Maryland Interconnection
Supplemental Agreement, dated March 26, 1981, between Public
Service Electric & Gas Company, Philadelphia Electric Company,
Pennsylvania Power & Light Company, Baltimore Gas & Electric
Company, Jersey Central Power & Light Company, Metropolitan
Edison Company, Pennsylvania Electric Company, Potomac Electric
Power Company, Atlantic City Electric Company and Delmarva Power
& Light Company (File No. 1-3559, Form 10-Q for quarter ended
March 31, 1981-Exhibit No. 20b).

24  Independent Auditors' Consent, filed herewith.

25a  Powers of Attorney for Atlantic Energy, Inc. dated as of
March 14, 1996, filed herewith.

25b  Powers of Attorney for Atlantic City Electric Company dated
as of March 11, 1996, filed herewith.

27 Financial Data Schedules for Atlantic Energy, Inc. and
Atlantic City Electric Company for periods ended December 31,
1995.

28(a)  Consolidated Financial Statements, Notes to Financial
Statements, Management's Discussion and Analysis of Results of
Operation and Financial Condition, and Independent Auditors'
Report for Atlantic City Electric Company for the three years
ended December 31, 1995, filed herewith.

28(b)  Supplemental Financial Schedules for Atlantic Energy, Inc.
and Atlantic City Electric Company for the three years ended
December 31, 1995, filed herewith.